S-4/A 1 file001.htm AMENDMENT NO. 1 TO FORM S-4

As filed with the Securities and Exchange Commission on June 11, 2003

Registration No. 333-105690

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 1
TO
FORM S-4

REGISTRATION STATEMENT UNDER

THE SECURITIES ACT OF 1933

MidAmerican Energy Holdings Company

(Exact name of registrant as specified in its charter)


Iowa 4900 94-2213782
(State or other jurisdiction of
incorporation or organization)		 (Primary Standard Industrial
Classification Code Numbers)		 (I.R.S. Employer
Identification Numbers)

666 Grand Avenue
Des Moines, Iowa 50309
(515) 242-4300
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Douglas L. Anderson
General Counsel
MidAmerican Energy Holdings Company
302 South 36th Street
Suite 400
Omaha, Nebraska 68131
(402) 341-4500
(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copy to:
Peter J. Hanlon, Esq.
Willkie Farr & Gallagher
787 Seventh Avenue
New York, New York 10019
(212) 728-8000

Approximate date of commencement of proposed sale to the public: As soon as practicable following the effective date of this Registration Statement.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. [ ]

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ]

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ]

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, Dated June 11, 2003

Prospectus

Offer to Exchange

Up to $450,000,000 3.50% Senior Notes due 2008 for

All outstanding 3.50% Senior Notes due 2008

• We are offering to exchange new registered 3.50% senior notes due 2008 for all of our outstanding unregistered 3.50% senior notes due 2008.
• The exchange offer expires at 5:00 p.m., New York City time, on July 11, 2003, unless extended.
• The exchange offer is subject to customary conditions that may be waived by us.
• All original notes outstanding that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer will be exchanged for the exchange notes.
• Tenders of original notes may be withdrawn at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer.
• The exchange of original notes for exchange notes will not be a taxable exchange for U.S. federal income tax purposes.
• We will not receive any proceeds from the exchange offer.
• The terms of the exchange notes to be issued are substantially identical to the terms of the original notes, except that the exchange notes will not have transfer restrictions, and you will not have registration rights.
• There is no established trading market for the exchange notes, and we do not intend to apply for listing of the exchange notes on any securities exchange or market quotation system.

See "Risk Factors" beginning on page 9 for a discussion of matters you should consider before you participate in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this Prospectus is June     , 2003

TABLE OF CONTENTS


  Page
SUMMARY   1  
RISK FACTORS   9  
FORWARD-LOOKING STATEMENTS   19  
USE OF PROCEEDS   20  
THE EXCHANGE OFFER   21  
CAPITALIZATION   30  
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA   31  
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   33  
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK   49  
BUSINESS   50  
REGULATION   69  
LEGAL PROCEEDINGS   83  
MANAGEMENT   86  
DESCRIPTION OF THE NOTES   95  
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS   111  
PLAN OF DISTRIBUTION   112  
NOTICE TO CANADIAN RESIDENTS   112  
LEGAL MATTERS   113  
EXPERTS   113  
WHERE YOU CAN FIND MORE INFORMATION   113  
FINANCIAL STATEMENTS   F-1  

In this prospectus, references to "U.S. dollars," "dollars," "US $," "$" or "cents" are to the currency of the United States, references to "£," "British pound," "sterling," "pence" or "p" are to the currency of the United Kingdom and references to "pesos" are to the currency of the Philippines. References to MW means megawatts, MWh means megawatt hours, kWh means kilowatt hours, Bcf means billion cubic feet, mmcf means million cubic feet, MMBtus means million British thermal units, Dth means decatherm, which is equivalent to one MMBtu, GWh means gigawatts per hour, kV means one thousand volts, and Tcf means trillion cubic feet.


This prospectus incorporates important business and financial information about us that is not included or delivered with this prospectus. We will provide this information to you at no charge upon written or oral request directed to Douglas L. Anderson, General Counsel, MidAmerican Energy Holdings Company, 302 South 36th Street, Suite 400, Omaha, Nebraska 68131, (402) 341-4500. In order to ensure timely delivery of the information, any request should be made by July 3, 2003.

No dealer, salesperson or other individual has been authorized to give any information or to make any representations not contained in this prospectus in connection with the exchange offer. If given or made, such information or representations must not be relied upon as having been authorized by us. Neither the delivery of this prospectus nor any sale made hereunder shall, under any circumstances, create any implications that there has not been any change in the facts set forth in this prospectus or in our affairs since the date hereof.


    Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. The letter of transmittal accompanying this prospectus states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act of 1933, as amended. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of the exchange notes received in exchange for original notes where such original notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 120 days after the expiration of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resales. See "Plan of Distribution."

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NOTICE TO NEW HAMPSHIRE RESIDENTS

NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE THAT ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER, OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.

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SUMMARY

This section contains a general summary of certain of the information contained in this prospectus. It may not include all of the information that is important to you. You should read this entire prospectus, including the "Risk Factors" section and the financial statements and notes to those statements, before making an investment decision.

MIDAMERICAN ENERGY HOLDINGS COMPANY

Overview

We are a United States-based global energy company. Our principal businesses are regulated electric and natural gas utilities, regulated interstate natural gas transmission and electric power generation. Our operations are organized and managed on seven distinct platforms which we refer to as: MidAmerican Energy, Northern Natural Gas, Kern River, CE Electric UK (which includes Northern Electric and Yorkshire Electricity), CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and HomeServices. We account for each of these platforms as a separate operating segment. For information regarding these segments, see note 8 to the unaudited consolidated financial statements for the three months ended March 31, 2003 and note 21 to the consolidated financial statements for the year ended December 31, 2002 included in this prospectus. Through six of these platforms, we own and operate a combined electric and natural gas utility company in the United States, two natural gas pipeline companies in the United States, two electricity distribution companies in the United Kingdom and a diversified portfolio of domestic and international electric power projects. We also own the second largest residential real estate brokerage firm in the United States. The following is a chart of our operating platforms and the principal lines of business in which they are engaged:

Our principal subsidiaries generate, transmit, store, distribute and supply energy. Our electric and natural gas utility subsidiaries currently serve approximately 4.3 million electricity customers and approximately 660,000 natural gas customers. Our natural gas pipeline subsidiaries operate interstate natural gas transmission systems with approximately 18,300 miles of pipeline in operation and peak delivery capacity of 6.2 Bcf of natural gas per day. We have interests in 6,191 net owned MW of power generation facilities in operation and construction, including 4,618 net owned MW in facilities that are part of the regulated return asset base of our electric utility business and 1,573 net owned MW in non-utility power generation facilities. Substantially all of the non-utility power generation facilities have long-term contracts for the sale of energy and/or capacity from the facilities.

We are a privately owned company with publicly held fixed income securities. Since March 14, 2000, our sole shareholders have consisted of a private investor group comprised of Berkshire Hathaway Inc., or Berkshire Hathaway, Walter Scott, Jr. and members of his family, David L. Sokol, our Chairman and Chief Executive Officer, and Gregory E. Abel, our President and Chief Operating Officer. Prior to that time, our common stock was publicly traded on the New York Stock Exchange.

Our principal executive offices are located at 666 Grand Avenue, Des Moines, Iowa 50309, and our telephone number is (515) 242-4300.

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THE EXCHANGE OFFER

On May 16, 2003, we privately placed $450,000,000 principal amount of 3.50% senior notes due 2008, which we refer to as the original series C notes, in a transaction exempt from registration under the Securities Act of 1933, as amended, or the Securities Act. In connection with the private placement, we entered into a registration rights agreement, dated as of May 13, 2003, with the initial purchasers of the original series C notes. In the registration rights agreement, we agreed to offer our new 3.50% senior notes due 2008, which will be registered under the Securities Act, and which we refer to as the series C exchange notes, in exchange for the original series C notes. The exchange offer is intended to satisfy our obligations under the registration rights agreement. We also agreed to deliver this prospectus to the holders of the original series C notes. In this prospectus we refer to the original series C notes and the series C exchange notes as the series C notes. You should read the discussion under the headings "Summary — Terms of the Notes" and "Description of Notes" for information regarding the series C notes.

The Exchange Offer This is an offer to exchange $1,000 in principal amount of series C exchange notes for each $1,000 in principal amount of original series C notes. The series C exchange notes are substantially identical to the original series C notes, except that the series C exchange notes will generally be freely transferable. We believe that you can transfer the series C exchange notes without complying with the registration and prospectus delivery provisions of the Securities Act if you:
• acquire the series C exchange notes in the ordinary course of your business;
• are not and do not intend to become engaged in a distribution of the series C exchange notes;
• are not an "affiliate" (within the meaning of the Securities Act) of ours;
• are not a broker-dealer (within the meaning of the Securities Act) that acquired the original series C notes from us or our affiliates; and
• are not a broker-dealer (within the meaning of the Securities Act) that acquired the original series C notes in a transaction as part of its market-making or other trading activities.
If any of these conditions are not satisfied and you transfer any series C exchange note without delivering a proper prospectus or without qualifying for a registration exemption, you may incur liability under the Securities Act. See "The Exchange Offer — Terms of the Exchange."
Registration Rights Agreement Under the registration rights agreement, we have agreed to use our reasonable best efforts to consummate the exchange offer or cause the original series C notes to be registered under the Securities Act to permit resales. If we are not in compliance with our obligations under the registration rights agreement, liquidated damages will accrue on the original series C notes in addition to the

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interest that is otherwise due on the original series C notes. If the exchange offer is completed on the terms and within the time period contemplated by this prospectus, no liquidated damages will be payable on the original series C notes. The series C exchange notes will not contain any provisions regarding the payment of liquidated damages. See "The Exchange Offer — Liquidated Damages."
Minimum Condition The exchange offer is not conditioned on any minimum aggregate principal amount of original series C notes being tendered for exchange.
Expiration Date The exchange offer will expire at 5:00 p.m., New York City time, on July 11, 2003, unless we extend it.
Exchange Date Original series C notes will be accepted for exchange at the time when all conditions of the exchange offer are satisfied or waived. The series C exchange notes will be delivered promptly after we accept the original series C notes.
Conditions to the Exchange Offer Our obligation to complete the exchange offer is subject to certain conditions. See "The Exchange Offer — Conditions to the Exchange Offer." We reserve the right to terminate or amend the exchange offer at any time prior to the expiration date upon the occurrence of certain specified events.
Withdrawal Rights You may withdraw the tender of your original series C notes at any time before the expiration of the exchange offer on the expiration date. Any original series C notes not accepted for any reason will be returned to you without expense as promptly as practicable after the expiration or termination of the exchange offer.
Procedures for Tendering Original Notes See "The Exchange Offer — How to Tender."
United States Federal Income
    Tax Consequences		 The exchange of the original series C notes for series C exchange notes will not be a taxable exchange for U.S. federal income tax purposes, and holders will not recognize any taxable gain or loss as a result of such exchange.
Effect on Holders of Original Notes If the exchange offer is completed on the terms and within the period contemplated by this prospectus, holders of original series C notes will have no further registration or other rights under the registration rights agreement, except under limited circumstances. See "The Exchange Offer — Other."

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Holders of original series C notes who do not tender their original series C notes will continue to hold those original series C notes. All untendered, and tendered but unaccepted, original series C notes will continue to be subject to the transfer restrictions provided for in the original series C notes and the indenture under which the original series C notes have been issued. To the extent that original series C notes are tendered and accepted in the exchange offer, the trading market, if any, for the original series C notes could be adversely affected. See "Risk Factors — Risks Associated with the Exchange Offer — You may not be able to sell your original series C notes if you do not exchange them for registered series C exchange notes in the exchange offer."; " — Your ability to sell your original series C notes may be significantly more limited and the price at which you may be able to sell your original series C notes may be significantly lower if you do not exchange them for registered series C exchange notes in the exchange offer."; and "The Exchange Offer — Other."
Use of Proceeds We will not receive any proceeds from the issuance of series C exchange notes in the exchange offer.
Exchange Agent The Bank of New York is serving as the exchange agent in connection with the exchange offer.

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TERMS OF THE SERIES C NOTES

General $450,000,000 aggregate principal amount of 3.50% Senior Notes due May 15, 2008. The original series C notes were, and the series C exchange notes will be, issued under a supplemental indenture, dated as of May 16, 2003, to the indenture, dated as of October 4, 2002, between us and The Bank of New York, as trustee. On October 4, 2002, we issued $200,000,000 of our 4.625% Senior Notes due 2007 and $500,000,000 of our 5.875% Senior Notes due 2012, which are hereafter referred to as the series A notes and series B notes, respectively, pursuant to the indenture. Unless otherwise indicated, references hereafter to the notes in this prospectus include the series A notes, the series B notes and the series C notes (and any other series of notes or other securities hereafter issued under a supplemental indenture or otherwise pursuant to the indenture).
Interest Payment Dates May 15 and November 15 of each year, commencing November 15, 2003.
Optional Redemption We may redeem the series C notes, at our option, in whole or in part, at any time, at a redemption price equal to the greater of:
(1) 100% of the principal amount of the series C notes to be redeemed; or
(2) the sum of the present values of the remaining scheduled payments of principal of and interest on the series C notes to be redeemed discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at a discount rate equal to the yield on equivalent Treasury securities plus 25 basis points,
plus, for (1) or (2) above, whichever is applicable, accrued and unpaid interest, if any, on such series C notes to the date of redemption.
Sinking Fund The series C notes are not subject to a mandatory sinking fund.
Change of Control Upon the occurrence of a Change of Control, each holder of the notes will have the right, at the holder's option, to require us to repurchase all or any part of the holder's notes at a purchase price in cash equal to 101% of the principal thereof, plus accrued and unpaid interest, if any, to the date of such purchase in accordance with the procedures set forth in the indenture for the notes. A Change of Control means the occurrence of both of the following: (1) a transaction pursuant to which Berkshire

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Hathaway ceases to own, on a diluted basis, at least a majority of our common stock, assuming conversion of all convertible securities then owned by Berkshire Hathaway, without regard to whether then presently convertible, or we or our subsidiaries dispose of all or substantially all of our property and that of our subsidiaries to any entity which is not so majority owned by Berkshire Hathaway, and (2) within 90 days after the earlier of the announcement or occurrence of any such transaction, a downgrade in the ratings for the notes (generally to below investment grade by both Moody's Investors Service, Inc., or Moody's, and Standard & Poor's Rating Service, or S&P) occurs. See "Description of the Notes — Covenants — Purchase of Notes Upon a Change of Control."
Ranking The series C notes are our general, unsecured senior obligations and will rank pari passu in right of payment with all our other existing and future senior unsecured obligations (including the series A notes and series B notes) and senior in right of payment to all our existing and future subordinated obligations. The series C notes are effectively subordinated to all our existing and future secured obligations and to all existing and future obligations of our subsidiaries.
Covenants The indenture contains covenants that, among other things, restrict our ability to grant liens on our assets and our ability to merge, consolidate or transfer or lease all or substantially all of our assets. See "Description of the Notes — Covenants."
Events of Default Events of default with respect to the notes of any series under the indenture include, among other things:
(1) default in the payment of any interest on any notes of that series for 30 days after payment is due;
(2) default in the payment of principal of, or premium, if any, on any note of that series or as to any payment required in connection with a Change of Control as described above;
(3) our failure to perform, or breach by us of, any covenant contained in the indenture or the notes of that series, which failure continues for 30 days after written notice thereof is provided to us pursuant to the indenture;
(4) our failure or the failure of any of our significant subsidiaries (as defined later in this prospectus) to pay when due beyond any applicable grace period, or the acceleration of, debt (other than debt that is non-recourse to us) in excess of $100,000,000;

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(5) the entry by a court of one or more judgments against us or any of our significant subsidiaries (other than a judgment that is non-recourse to us) requiring payment by us in an aggregate amount in excess of $100,000,000 which has not been vacated, discharged, satisfied or stayed pending appeal within 60 days from entry; and
(6) the occurrence of certain events of bankruptcy, insolvency or reorganization with respect to us or any of our significant subsidiaries.
See "Description of the Notes — Definitions" and "— Events of Default."
Ratings The series C notes have initially been assigned ratings of Baa3 by Moody's, BBB– by S&P and BBB by Fitch, Inc. However, these ratings are subject to change at any time.
Denomination and Form The original series C notes were, and the series C exchange notes will be, issued in denominations of $1,000 and any integral multiple of $1,000. The original series C notes were, and the series C exchange notes will be, represented by one or more global securities registered in the name of The Depository Trust Company or its nominee. Beneficial interests in the global securities representing the original series C notes are, and beneficial interests in the global securities representing the series C exchange notes will be, shown on, and transfers of the beneficial interests in the global securities representing the original series C notes are, and transfers of the beneficial interests in the global securities representing the series C exchange notes will be, effected only through, records maintained by DTC and its participants. Except as described later in this prospectus, series C notes in certificated form will not be issued. See "Description of the Notes — Global Notes; Book-Entry System."
Trustee The Bank of New York is the trustee for the holders of the series C notes.
Governing Law The series C notes, the indenture and the other documents for the offering of the series C notes are governed by the laws of the State of New York.

Risk Factors

This investment involves risks. Before you invest in the series C notes, you should carefully consider the matters set forth under the heading "Risk Factors" and all other information in this prospectus.

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Summary Selected Historical Consolidated Financial and Operating Data

The following table presents our summary historical consolidated financial and operating data as of and for the years ended December 31, 2002, 2001 and 2000, and as of March 31, 2003, and for the three-month periods ended March 31, 2003 and 2002. Our unaudited consolidated financial statements as of March 31, 2003 and for the three-month periods ended March 31, 2003 and 2002 reflect all adjustments (consisting of normal recurring accruals) necessary in the opinion of our management for a fair presentation of such data. The financial data set forth below should be read in conjunction with our historical consolidated financial statements and the notes thereto appearing elsewhere in this prospectus. All amounts (except for ratios) are presented in thousands.


            Our Predecessor
  Three Months Ended
March 31,		 Year Ended
December 31,		 March 14,
2000 through
December 31,
2000(3)		 January 1,
2000 through
March 13,
2000(4)
  2003 2002 2002(1) 2001(2)
STATEMENT OF OPERATIONS DATA:
Operating revenue $ 1,562,834   $ 1,041,752   $ 4,794,010   $ 4,696,781   $ 3,918,100   $ 1,056,365  
Total revenue   1,603,954     1,069,577     4,968,139     4,972,980     4,012,982     1,075,849  
Depreciation and amortization   141,849     126,244     525,902     538,702     383,351     97,278  
Interest expense, net of capitalized interet   171,313     134,653     609,910     412,794     311,404     85,814  
Income before cumulative effect of change in accounting principle   130,636     64,749     380,043     147,273     81,257     51,312  
Net income available to common and preferred stockholders   130,636     64,749     380,043     142,669     81,257     51,312  
OTHER FINANCIAL DATA:
Capital expenditures relating to operating projects $ 133,845   $ 95,673   $ 542,615   $ 398,165   $ 301,948   $ 44,355  
Ratio of earnings to fixed charges (5)   2.3x     1.8x     1.9x     1.8x     1.3x     1.7x  
Net cash flows from operating activities   385,793     182,622     757,726     846,998     246,407     171,083  
Net cash flows from investing activities   (444,000 )    (886,690 )    (2,907,811 )    (238,544 )    (2,389,160 )    (54,874 ) 
Net cash flows from financing activities   73,549     1,029,196     2,555,234     (258,467 )    1,878,849     (128,501 ) 

  As of
March 31,
2003		 As of December 31,
  2002 2001 2000
BALANCE SHEET DATA:
Properties, plants and equipment, net $ 10,135,056   $ 9,898,796   $ 6,537,371   $ 5,348,647  
Total assets   18,408,960     18,016,455     12,626,652     11,610,939  
Short-term debt   70,932     79,782     256,012     261,656  
Current portion of long-term debt   364,358     470,213     317,180     438,978  
Parent company debt   2,325,756     2,324,456     1,834,498     1,829,971  
Subsidiary and project debt   7,231,794     7,077,087     4,754,811     3,388,696  
Total liabilities   13,765,764     13,478,006     9,778,757     8,911,349  
Parent company-obligated mandatorily Redeemable preferred securities held by Berkshire Hathaway   1,727,772     1,727,772     454,772     454,772  
Parent company-obligated mandatorily redeemable preferred securities held by others   336,163     335,640     333,379     331,751  
Total shareholders' equity   2,402,005     2,294,283     1,708,167     1,576,401  
(1) Reflects the acquisitions of Kern River on March 27, 2002 and Northern Natural Gas on August 16, 2002.
(2) Reflects the Yorkshire Swap on September 21, 2001 (as described under "Business — CE Electric UK") and includes $15.2 million of non-recurring net income related to the sale of the Northern Electric electricity and gas supply business, the sale of the Telephone Flat Project, the sale of Western States Geothermal, the transfer of Bali Energy Ltd. shares, and the Teesside Power Limited, or TPL, asset valuation impairment charge.
(3) Reflects the Teton Transaction (as described under "Business — General") on March 14, 2000.
(4) Includes $7.6 million of net non-recurring expenses for the costs related to the Teton Transaction on March 14, 2000.
(5) For purposes of computing the ratio of earnings to fixed charges, earnings are divided by fixed charges. Earnings represent the aggregate of (a) our pre-tax income and (b) fixed charges, less capitalized interest. Fixed charges represent interest (whether expensed or capitalized), amortization of deferred financing and bank fees, and the estimated interest component of rentals.

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RISK FACTORS

An investment in the series C notes is subject to numerous risks, including, but not limited to, those set forth below. In addition to the information contained elsewhere in this prospectus, you should carefully consider the following risk factors when evaluating an investment in the series C notes.

Risk Associated with Our Corporate and Financial Structure

We are a holding company that depends on distributions from our subsidiaries and joint ventures to meet our needs.

We are a holding company and derive substantially all of our income and cash flow from our subsidiaries and joint ventures. We expect that future development and acquisition efforts will be similarly structured to involve operating subsidiaries and joint ventures. We are dependent on the earnings and cash flows of, and dividends, loans, advances or other distributions from, our subsidiaries and joint ventures to generate the funds necessary to meet our obligations, including the payment of principal of, or interest and premium, if any, on, the notes. All required payments on debt and preferred stock at subsidiary levels will be made before funds from our subsidiaries are available to us. The availability of distributions from such entities is also subject to:

• their earnings and capital requirements,
• the satisfaction of various covenants and conditions contained in financing documents by which they are bound or in their organizational documents, and
• in the case of our regulated utility subsidiaries, regulatory restrictions which restrict their ability to distribute profits to us.

Our subsidiaries and joint ventures are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due pursuant to the notes or to make any funds available, whether by dividends, loans or other payments, for payment of the notes, and do not guarantee the payment of interest or premium, if any, on or principal of the notes.

We are substantially leveraged and the notes will be structurally subordinated to the indebtedness of our subsidiaries.

Our substantial leverage level presents the risk that we might not generate sufficient cash to service our indebtedness, including the notes, or that our leveraged capital structure could limit our ability to finance future acquisitions, develop additional projects, compete effectively and operate successfully under adverse economic conditions. At March 31, 2003, our outstanding indebtedness was approximately $2.5 billion (excluding $2.1 billion in aggregate principal amount of our trust preferred securities, our guarantees and letters of credit in respect of subsidiary indebtedness aggregating approximately $231 million and our recently terminated completion guarantee issued in favor of the lenders under Kern River's recently refinanced $875 million construction loan facility in connection with Kern River's expansion for which it filed an application with the Federal Energy Regulatory Commission, or the FERC, in Docket No. CP01-422-000, on August 1, 2001 and which was placed into service on May 1, 2003, or the 2003 Expansion Project). In addition, our subsidiaries have significant amounts of indebtedness. At March 31, 2003, our consolidated subsidiaries' and joint ventures' total outstanding indebtedness was approximately $7.4 billion, which does not include $432 million, representing our share of outstanding indebtedness of CE Generation, LLC, or CE Gen. This amount also does not include trade debt or preferred stock obligations of our subsidiaries. The terms of the notes do not limit our ability or the ability of our subsidiaries or joint ventures to incur additional debt or issue additional preferred stock. Claims of creditors of our subsidiaries and joint ventures will have priority over your claims with respect to the assets and earnings of our subsidiaries and joint ventures. In addition, the stock or assets of substantially all of our operating subsidiaries and joint ventures is directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of the notes.

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Risks Associated with our Business

Our recent growth has been achieved, in part, through strategic acquisitions, and additional acquisitions may not be successful.

Because our industry is rapidly changing, there are opportunities for acquisitions of assets and businesses, as well as for business combinations. We investigate opportunities that may increase shareholder value and build on existing businesses. We have participated in the past and our security holders may assume that at any time we may be participating in bidding or other negotiations for such transactions. This participation may or may not result in a transaction for us. Any transaction that does take place may involve consideration in the form of cash, debt or equity securities.

Since 1996, we have completed several significant acquisitions, including the acquisitions of Northern Electric, Yorkshire Electricity, MidAmerican Energy, Kern River and Northern Natural Gas. We intend to continue to actively pursue acquisitions in the energy industry to complement and diversify our existing business for the foreseeable future.

The successful integration of any businesses we may acquire in the future will entail numerous risks, including, among others, the risk of diverting management's attention from day-to-day operations, the risk that the acquired businesses will require substantial capital and financial investments and the risk that the investments will fail to perform in accordance with expectations. Any substantial diversion of management attention and any substantial difficulties encountered in the transition and integration process could have a material adverse effect on the revenues, levels of expenses and operating results of the company.

In addition, it has been publicly reported over the past two years that many of the participants in the United States energy industry, including the prior owners of Kern River and Northern Natural Gas and potentially including other industry participants from whom we may choose to purchase additional businesses in the future, have recently had or may have liquidity, creditworthiness and other financial difficulties. As a consequence, there can be no assurance that any such sellers will not enter into bankruptcy or insolvency proceedings or that they will otherwise be able, required or willing to perform on their indemnification obligations to us if we should elect to pursue any such claims we may have against any of them under our acquisition agreements in the future. If our due diligence efforts were or are unsuccessful in identifying and analyzing all material liabilities relating to acquired companies and if there were to be any material undisclosed liabilities, or if there were to be other unexpected consequences from any such bankruptcy or insolvency proceeding, such as a successful challenge as to whether the prices paid by us constituted reasonably equivalent value within the meaning of the relevant bankruptcy laws, then any such bankruptcy or insolvency, or failure by any of these sellers to perform their indemnification obligations to us, could have a material adverse effect on our business, financial condition, results of operations and the market prices and rates for our securities.

We cannot assure you that future acquisitions, if any, or any related integration efforts will be successful, or that our ability to repay the notes will not be adversely affected by any future acquisitions.

We are actively pursuing, developing and constructing new or expanded facilities, the completion and expected cost of which is subject to significant risk.

Through our operating subsidiaries, we are continuing to develop, construct, own and operate new or expanded facilities, including the project to recover zinc from the geothermal brine utilized at the Imperial Valley site in California, or the Zinc Recovery Project, and three planned electric generating projects in Iowa, and in the future we expect to pursue the development, construction, ownership and operation of additional new or expanded energy projects (including, without limitation, generation, distribution, transmission, exploration/production, storage and supply projects and related activities, infrastructure and services), both domestically and internationally, the completion of any of which, including any future projects, is subject to substantial risk and may expose us to significant costs. We cannot assure you that our development or construction efforts on any particular project, or our efforts generally, will be successful.

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Also, a proposed expansion or project may cost more than planned to complete, and such excess costs, if related to a regulated asset and found to be imprudent, may not be recoverable in rates. The inability to successfully and timely complete a project or avoid unexpected costs may require us to perform under guarantees, and the inability to avoid unsuccessful projects or to recover any excess costs may materially affect our ability to service our obligations under the notes.

Our subsidiaries are subject to certain operating uncertainties which may adversely affect revenues, expenses or distributions.

The operation of complex electric and gas utility (including transmission and distribution systems), pipeline or power generating facilities involves many operating uncertainties and events beyond our control. Operating risks include the breakdown or failure of power generation equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, fuel interruption, performance below expected levels of output, capacity or efficiency, operator error and catastrophic events such as severe storms, fires, earthquakes or explosions. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Revenues, expenses and distributions may also be adversely affected by general economic, business, regulatory and weather conditions. The realization of any of these risks could significantly reduce or eliminate our affiliates' revenues or significantly increase our affiliates' expenses, thereby adversely affecting the ability to receive distributions from subsidiaries and joint ventures.

We currently possess property, catastrophic and general liability insurance, but proceeds from such insurance coverage may not be adequate for all liabilities incurred, lost revenue or increased expenses. Moreover, such insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks have made it more difficult for us to obtain certain types of coverage. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or that it will otherwise cover all potential losses.

Acts of sabotage and terrorism aimed at our facilities could adversely affect our business.

Since the September 11, 2001 terrorist attacks, the United States government has issued warnings that energy assets, specifically our nation's pipeline and utility infrastructure, may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future acts of sabotage or terrorism aimed at our facilities, or those of our customers, could have a material adverse effect on our business, financial condition, results of operations and ability to service the notes. Any resulting acts of war or the threat of war as a result of such terrorist attacks could adversely affect the economy and energy consumption. Instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability to raise capital.

We are subject to comprehensive energy regulation and changes in regulation and rates may adversely affect our business, financial condition, results of operations and ability to service the notes.

We are subject to comprehensive governmental regulation, including regulation in the United States by various federal, state and local regulatory agencies, regulation in the United Kingdom and regulation in the Philippines, all of which significantly influences our operating environment, our rates, our capital structure, our costs and our ability to recover our costs from customers. These regulatory agencies include, among others, the FERC, the Environmental Protection Agency, or the EPA, the Nuclear Regulatory Commission, or the NRC, the United States Department of Transportation, the Iowa Utilities Board, or the IUB, the Illinois Commerce Commission, other state utility boards, numerous local agencies, the Gas and Electricity Markets Authority, or GEMA, which in discharging certain of its powers acts through its staff within the Office of Gas and Electricity Markets, or Ofgem, in the United Kingdom, and various other governmental agencies in the United Kingdom and the Philippines. We are currently exempt from the requirement to register with the Securities and Exchange Commission, or SEC, under the Public Utility Holding Company Act of 1935, as amended, or PUHCA, but if we were to cease to be exempt or if we were to become a subsidiary of a

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non-exempt holding company, we would become subject to additional regulation by the SEC under PUHCA. Under PUHCA, registered holding companies and their subsidiaries are subject to regulation and restrictions with respect to certain of their activities, including securities issuances, acquisitions, investments and affiliate transactions. The FERC has jurisdiction over, among other things, wholesale rates for electric transmission service and electric energy sold in interstate commerce, interstate natural gas transportation and storage rates, the siting and construction of interstate natural gas transportation facilities and certain other activities of our utility subsidiaries. United States federal, state and local agencies also have jurisdiction over many of our other activities. The utility commissions in the states where our utility subsidiaries operate regulate many aspects of our utility operations including siting and construction of facilities, customer service and the rates that we can charge customers. The revenues of our United Kingdom distribution businesses are subject to review and adjustment by GEMA and many other aspects of our subsidiaries' United Kingdom operations are subject to the jurisdiction of GEMA and other regulators and agencies in the United Kingdom.

The structure of federal and state energy regulation is currently undergoing change and has in the past, and may in the future, be the subject of various challenges, initiatives and restructuring proposals by policy makers, utilities and other industry participants. In addition to Congressional initiatives, many states and the FERC are implementing or considering regulatory initiatives designed to increase competition in the domestic power generation industry and increase access to electric utilities' transmission and distribution systems for independent power producers and electricity consumers. The implementation of regulatory changes in response to such challenges, initiatives and restructuring proposals could result in the imposition of more comprehensive or stringent requirements on us or our subsidiaries or other industry participants, which would result in increased compliance costs and could have a material adverse effect on our business, financial condition, results of operations and ability to service the notes.

We are unable to predict the impact on our operating results from the future regulatory activities of any of the agencies that currently regulate us or of the SEC under PUHCA. Changes in regulations or the imposition of additional regulations could have a material adverse impact on our results of operations. Recent developments, events and uncertainties which have impacted or could impact our businesses are described below.

On July 31, 2002, the FERC issued a notice of proposed rulemaking with respect to "Standard Market Design" for the electric industry. The FERC initially characterized the proposal as portending "sweeping changes" to the use and expansion of the interstate transmission and wholesale bulk power systems in the United States. The proposal includes numerous proposed changes to the current regulation of transmission and generation facilities designed "to promote economic efficiency" and to replace the "obsolete patchwork we have today," according to the FERC Chairman. More recently, on April 28, 2003, the FERC issued a white paper describing how it intends to change the proposed rulemaking. The white paper, which uses the term "Wholesale Market Platform" in lieu of the term "Standard Market Design," indicates that a final rule may focus on the formation of regional transmission organizations and allow for regional differences. The proposed rule may impact the costs of our electricity and transmission products. A final rule is unlikely to be fully implemented until at least 2004. We are still evaluating the proposed rule and recognize there is uncertainty as to the timing and outcome of this rulemaking. Accordingly, the likely impact of the proposed rule on our transmission and generation businesses is unknown.

The state utility regulatory environment has to date, in general, given MidAmerican Energy an exclusive right to serve retail electricity customers within its primary service territory in Iowa and, in turn, the obligation to provide electric service to those customers. There can be no assurance that there will not be a change in legislation or regulation in Iowa or in any of the other states in which we operate to allow retail competition in MidAmerican Energy's service territory.

Because our Kern River and Northern Natural Gas pipeline systems are interstate natural gas pipelines subject to regulation as natural gas companies under the Natural Gas Act, as amended, the rates we can charge our customers and other terms and conditions of service are subject to review by

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the FERC and the possibility of modification in periodic rate proceedings or at any time in response to a complaint proceeding initiated by a customer or on the FERC's own initiative. The rates, terms and conditions for transportation services of Kern River and Northern Natural Gas are required to be just and reasonable and not unduly discriminatory or preferential. Traditionally, the FERC has established rates for interstate gas pipelines, including those of Kern River and Northern Natural Gas, on a cost-of-service basis intended to allow such pipelines to recover their costs to construct, own, operate and maintain their pipelines which are actually and prudently incurred and to afford the pipelines an opportunity to earn a reasonable rate of return. Our pipeline tariffs also permit us to charge negotiated rates for transportation services to certain shippers subject to the availability of base tariff rates, or recourse rates, calculated on a traditional cost-of-service basis and provided that non-rate terms and conditions in any agreement do not deviate in any material aspect from those set forth in the applicable form of service agreement contained in the tariff. No assurance can be given that the FERC will not alter or refine its preferred methodology for establishing pipeline rates and tariff structures. Under the terms of our transportation service contracts and in accordance with the FERC's rate making principles, our current maximum tariff rates are designed to recover costs included in our pipeline systems' regulatory cost of service that are associated with the construction and operation of our pipeline systems that are actually, reasonably and prudently incurred. There can be no assurance that all costs we incur will be recoverable through existing or future rates. Failure to recover material costs may have a material adverse effect on our business, financial condition, results of operations and ability to service the notes.

Revenue from Northern Electric's and Yorkshire Electricity's distribution business is controlled by a distribution price control formula which determines the maximum average price per unit of electricity that a distribution network operator in Great Britain may charge. The distribution price control formula is expected to have a five-year duration and is subject to review by GEMA at the end of each five-year period and at other times in the discretion of GEMA. At each review, GEMA can propose adjustments to the distribution price control formula. In December 1999, a review resulted in a reduction in allowed revenue of 24% for Northern Electric's distribution business and 23% for Yorkshire Electricity's distribution business, in real terms, with effect from and after April 1, 2000. The next review of the distribution price control formula is expected to become effective in April 2005. Any further price reviews by GEMA, including those it may elect to conduct at any time in its discretion, may have a material adverse effect on our results of operations.

The Philippine Congress has passed the Electric Power Reform Act of 2001, which is aimed at restructuring the power industry, including privatization of the National Power Corporation, or the NPC, and introduction of a competitive electricity market, among other things. The implementation of the bill may have an adverse impact on our operations in the Philippines and the Philippine power industry as a whole.

We are subject to environmental, health, safety and other laws and regulations which may adversely impact us.

Through our subsidiaries and joint ventures, we are subject to a number of environmental, health, safety and other laws and regulations affecting many aspects of our present and future operations, both domestic and foreign, including air emissions, water quality, wastewater discharges, solid wastes, hazardous substances and safety matters. We may incur substantial costs and liabilities in connection with our operations as a result of these regulations. In particular, the cost of future compliance with federal, state and local clean air laws, such as those that require certain generators, including some of our subsidiaries' electric generating facilities, to limit nitrogen oxide emissions and potential other pollutants, may require us to make significant capital expenditures which may not be recoverable through future rates. In addition, these costs and liabilities may include those relating to claims for damages to property and persons resulting from our operations. The implementation of regulatory changes imposing more comprehensive or stringent requirements on us, to the extent such changes would result in increased compliance costs or additional operating restrictions, could have a material adverse effect on our business, financial condition, results of operations and ability to service the notes.

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In addition, regulatory compliance for existing facilities and the construction of new facilities is a costly and time-consuming process, and intricate and rapidly changing environmental regulations may require major expenditures for permitting and create the risk of expensive delays or material impairment of value if projects cannot function as planned due to changing regulatory requirements or local opposition.

Potential pipeline safety legislation and an increase in public expectations on pipeline safety may also require replacement of some of our pipeline segments, addition of monitoring equipment, and more frequent inspection or testing of our pipeline facilities. These requirements coupled with increases in state and federal agency oversight, if adopted, would necessitate additional testing and reporting which may result in higher operating costs and/or capital costs. Our FERC-approved tariffs or competition from other natural gas sources may not allow us to recover these increased costs of compliance.

In addition to operational standards, environmental laws also impose obligations to clean up or remediate contaminated properties or to pay for the cost of such remediation, often upon parties that did not actually cause the contamination. Accordingly, we may become liable, either contractually or by operation of law, for remediation costs even if the contaminated property is not presently owned or operated by us, or if the contamination was caused by third parties during or prior to our ownership or operation of the property. Given the nature of the past industrial operations conducted by us and others at our properties, there can be no assurance that all potential instances of soil or groundwater contamination have been identified, even for those properties where an environmental site assessment or other investigation has been conducted. Although we have accrued reserves for our known remediation liabilities, future events, such as changes in existing laws or policies or their enforcement, or the discovery of currently unknown contamination, may give rise to additional remediation liabilities which may be material.

Any failure to recover increased environmental, health or safety costs incurred by us may have a material adverse effect on our business, financial condition, results of operations and ability to service the notes.

Increased competition resulting from legislative, regulatory and restructuring efforts could have a significant financial impact on us and our utility subsidiaries and consequently decrease our revenue.

The energy market continues to move towards a competitive environment and is characterized by numerous strong and capable competitors, many of which have more extensive operating experience and greater financial resources than we and our subsidiaries. Retail competition and the unbundling of regulated energy and gas service could have a significant adverse financial impact on us and our subsidiaries due to an impairment of assets, a loss of customers, lower profit margins and/or increased costs of capital. The total impacts of restructuring may have a significant financial impact on our financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impacts of these changes on our financial position, results of operations or cash flows.

The generation segment of the electric industry has been and will be significantly impacted by competition. The introduction of competition in the wholesale market has resulted in a proliferation of power marketers and a substantial increase in market activity. Many of these marketers have experienced financial difficulties and the market continues to be volatile.

As retail competition continues to evolve, margins will be pressured by competition from other utilities, power marketers and self-generation. Many states and the federal government are implementing or considering regulatory initiatives that would increase access to electric utilities' transmission and distribution systems for independent power producers, utilities, power marketers and electricity customers. Although the recent and anticipated changes in the United States electric utility industry may create opportunities, they will also create additional challenges and risks for utilities. Competition will put pressure on margins for traditional electric services. Illinois recently enacted a law that provides for full retail customer choice. While introduction of retail competition in Iowa is not presently expected, depending upon the terms of any such legislation, if introduced it could have a

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material adverse effect on us. These types of restructurings and other industry restructuring efforts could materially impact our results of operations in a manner which is difficult to predict, since such efforts will depend on the terms and timing of such restructuring.

As a result of a number of FERC orders, including Order No. 636, the FERC's policies favoring competition in gas markets, the expansion of existing pipelines and the construction of new pipelines, the interstate pipeline industry has begun to experience some failure to renew, or turn back, of firm capacity, as existing transportation service agreements expire and are terminated. Local distribution companies, or LDCs, and end-use customers have more choices in the new, more competitive environment and may be able to obtain service from more than one pipeline to fulfill their natural gas delivery requirements. If a pipeline experiences capacity turn back and is unable to remarket the capacity, the pipeline or its remaining customers may have to bear the costs associated with the capacity that is turned back. Any new pipelines that are constructed could compete with our pipeline subsidiaries for customers' service needs. Increased competition could reduce the volumes of gas transported by our pipeline subsidiaries or, in cases where they do not have long-term fixed rate contracts, could force our pipeline subsidiaries to lower their rates to meet competition. This could adversely affect our pipeline subsidiaries' financial results.

A significant decrease in demand for natural gas in the markets served by our subsidiaries' pipeline and distribution systems would significantly decrease our revenue and thereby adversely affect our business, financial condition, results of operations and ability to service the notes.

A sustained decrease in demand for natural gas in the markets served by our subsidiaries' pipeline and distribution systems would significantly reduce our revenues. Factors that could lead to a decrease in market demand include:

• a recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on natural gas;
• an increase in the market price of natural gas or a decrease in the price of other competing forms of energy, including electricity, coal and fuel oil;
• higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or that limit the use of natural gas;
• a shift by consumers to more fuel-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, pending legislation proposing to mandate higher fuel economy, or otherwise; and
• a shift by our pipeline and distribution customers to the use of alternate fuels, such as fuel oil, due to price differentials or other incentives.

Failure of our significant power purchasers and pipeline customers to pay amounts due under their contracts could reduce our revenues materially.

Our subsidiaries' non-utility generating facilities and both of our pipeline subsidiaries are dependent upon a relatively small number of customers for a significant portion of their revenues. As a result, our profitability and ability to make payments under the notes generally will depend in part upon the continued financial performance and creditworthiness of these customers. Accordingly, failure of one or more of our most significant customers to pay for contracted electric generating capacity or pipeline capacity reservation charges, for reasons related to financial distress or otherwise, could reduce our revenues materially if we were not able to make adequate alternate arrangements, such as adequate replacement contracts. The replacement of any of our existing long-term contracts, should it become necessary, will depend on a number of factors beyond our control, including:

• the availability of economically deliverable natural gas for transport through our pipeline system, including in particular continued availability of adequate supplies from the Rocky Mountains, Hugoton, Permian, Anadarko and Western Canadian supply basins currently accessible to our pipeline subsidiaries;
• existing competition to deliver natural gas to the upper Midwest and southern California;

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• new pipelines or expansions potentially serving the same markets as our pipelines;
• the growth in demand for natural gas in the upper Midwest and southern California;
• whether transportation of natural gas pursuant to long-term contracts continues to be market practice; and
• whether our business strategy, including our expansion strategy, continues to be successful.

Any failure to replace a significant portion of these contracts on adequate terms or to make other adequate alternate arrangements, should it become necessary, may have a material adverse effect on our business, financial condition, results of operations and ability to service the notes.

Our utility and non-utility businesses are subject to market and credit risk.

We are exposed to market and credit risks in our subsidiaries' generation, retail distribution and pipeline operations. Specifically, such risks include commodity price changes, market supply shortages, interest rate changes and counterparty default. In Iowa, MidAmerican Energy does not have an ability to pass through fuel price increases in its rates (an energy adjustment clause), so any significant increase in fuel costs or purchased power costs could have a negative impact on MidAmerican Energy. To minimize these risks, we require collateral to be posted if the creditworthiness of counterparties deteriorates below established levels and enter into financial derivative instrument contracts to hedge purchase and sale commitments, fuel requirements and inventories of natural gas, electricity, coal and emission allowances. However, financial derivative instrument contracts do not eliminate the risk. The impact of these risks could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales contracts or increased interest expense.

We have significant operations outside the United States which may be subject to increased risk because of the economic or political conditions of the country in which they operate.

We have a number of operations outside of the United States. The acquisition, ownership and operation of businesses outside the United States entail significant political and financial risks (including, without limitation, uncertainties associated with privatization efforts, inflation, currency exchange rate fluctuations, currency repatriation restrictions, changes in law or regulation, changes in government policy, political instability, civil unrest and expropriation) and other risk/structuring issues that have the potential to cause material impairment of the value of the business being operated, which we may not be capable of fully insuring against. The risk of doing business outside of the United States could be greater than in the United States because of specific economic or political conditions of each country. The uncertainty of the legal environment in certain foreign countries in which we operate or may acquire projects or businesses could make it more difficult for us to enforce our rights under agreements relating to such projects or businesses. In addition, the laws and regulations of certain countries may limit our ability to hold a majority interest in some of the projects or businesses that we may acquire. Furthermore, the central bank of any such country may have the authority in certain circumstances to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to restrict distributions to foreign investors. Although we may structure certain project revenue and other agreements to provide for payments to be made in, or indexed to, United States dollars or a currency freely convertible into United States dollars, there can be no assurance that we will be able to obtain sufficient dollars or other hard currency or that available dollars will be allocated to pay such obligations.

Our international projects may be subject to the risk of being delayed, suspended or terminated by the applicable foreign governments or may be subject to the risk of contract abrogation, expropriations or other uncertainties resulting from changes in government policy or personnel or changes in general political or economic conditions affecting the country or otherwise. In this regard, reference is made to the substantial uncertainties described in note 6 to the unaudited consolidated financial statements for the three months ended March 31, 2003 included in this prospectus and note 20 to the consolidated financial statements for the year ended December 31, 2002 included in this prospectus relating to one of our non-utility power projects in the Philippines, which we refer to as the Casecnan Project. As is more fully described therein, certain payments under the primary

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Casecnan Project agreement are currently not being made by the government of the Philippines and are presently the subject of international arbitration. Specifically, under the terms of a Casecnan Project agreement between CE Casecnan Water and Energy Company, Inc., or CE Casecnan, and the Philippine National Irrigation Administration, or NIA, NIA has the option of timely reimbursing CE Casecnan directly for certain taxes CE Casecnan has paid. If NIA does not so reimburse CE Casecnan, the taxes paid by CE Casecnan result in an increase in the water delivery fee under the Casecnan Project agreement. The payment of certain other taxes by CE Casecnan results automatically in an increase in the water delivery fee. As of March 31, 2003, CE Casecnan had paid approximately $58.1 million in taxes which as a result of the foregoing provisions had resulted in an increase in the water delivery fee. NIA has failed to pay the portion of the water delivery fee each month which relates to the payment of these taxes by CE Casecnan. As a result of this non-payment, on August 19, 2002, CE Casecnan filed a Request for Arbitration against NIA, seeking payment of such portion of the water delivery fee and enforcement of the relevant provision of the Casecnan Project agreement in the future. The arbitration will be conducted in accordance with the rules of the International Chamber of Commerce, or ICC. In that arbitration, on April 23, 2003, the Philippine government asserted, among other things, that the Casecnan Project agreement is void or should be cancelled or reformed.

In connection with a build-operate-transfer project awarded to a consortium known as PIATCO (which is unrelated to us) for the development, construction and operation of the new Manila International Airport, despite the pendency of arbitration before the International Chamber of Commerce pursuant to the PIATCO project agreement, the Philippine Supreme Court accepted jurisdiction of litigation brought by certain Philippine political and union interests and ruled, on May 5, 2003, that the PIATCO agreement was contrary to Philippine law and public policy and was null and void. The potential impact of that decision upon the Casecnan Project is presently under review. Moody's has indicated that it has become increasingly concerned that this type of unpredictability of actions by Philippine government-related agencies and the consequent instability of contractual arrangements is becoming inconsistent with a rating approach that attaches significant benefit to offtake arrangements with those government-related agencies. On this basis, noting NIA's claim seeking to have the Casecnan Project agreement declared void, on May 8, 2003, Moody's placed CE Casecnan's senior secured notes on review for a possible downgrade.

We face exchange rate risk.

Payments from some of our foreign investments, including without limitation Northern Electric and Yorkshire Electricity, are made in a foreign currency and any dividends or distributions of earnings in respect of such investments may be significantly affected by fluctuations in the exchange rate between the United States dollar and the British pound or other applicable foreign currency. Although we may enter into certain transactions to hedge risks associated with exchange rate fluctuations, there can be no assurance that such transactions will be successful in reducing such risks.


Risks Associated with the Exchange Offer

You may not be able to sell your original series C notes if you do not exchange them for registered series C exchange notes in the exchange offer.

If you do not exchange your original series C notes for series C exchange notes in the exchange offer, your original series C notes will continue to be subject to the restrictions on transfer as stated in the legends on the original series C notes. In general, you may not offer, sell or otherwise transfer the original series C notes in the United States unless they are:

• registered under the Securities Act;
• offered or sold under an exemption from the Securities Act and applicable state securities laws; or
• offered or sold in a transaction not subject to the Securities Act and applicable state securities laws.

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We do not currently anticipate that we will register the original series C notes under the Securities Act. Except for limited instances involving the initial purchasers or holders of original series C notes who are not eligible to participate in the exchange offer or who receive freely transferable series C exchange notes in the exchange offer, we will not be under any obligation to register the original series C notes under the Securities Act under the registration rights agreement or otherwise. Also, if the exchange offer is completed on the terms and within the time period contemplated by this prospectus, no liquidated damages will be payable on your original series C notes.

Your ability to sell your original series C notes may be significantly more limited and the price at which you may be able to sell your original series C notes may be significantly lower if you do not exchange them for registered series C exchange notes in the exchange offer.

To the extent that original series C notes are exchanged in the exchange offer, the trading market for the original series C notes that remain outstanding may be significantly more limited. As a result, the liquidity of the original series C notes not tendered for exchange could be adversely affected. The extent of the market for original series C notes will depend upon a number of factors, including the number of holders of original series C notes remaining outstanding and the interest of securities firms in maintaining a market in the original series C notes. An issue of securities with a similar outstanding market value available for trading, which is called the "float," may command a lower price than would be comparable to an issue of securities with a greater float. As a result, the market price for original series C notes that are not exchanged in the exchange offer may be affected adversely to the extent that original series C notes exchanged in the exchange offer reduce the float. The reduced float also may make the trading price of the original series C notes that are not exchanged more volatile.

There are state securities law restrictions on the resale of the series C exchange notes.

In order to comply with the securities laws of certain jurisdictions, the series C exchange notes may not be offered or resold by any holder unless they have been registered or qualified for sale in such jurisdictions or an exemption from registration or qualification is available and the requirements of such exemption have been satisfied. We do not currently intend to register or qualify the resale of the series C exchange notes in any such jurisdictions. However, an exemption is generally available for sales to registered broker-dealers and certain institutional buyers. Other exemptions under applicable state securities laws may also be available.

We will not accept your original series C notes for exchange if you fail to follow the exchange offer procedures and, as a result, your original series C notes will continue to be subject to existing transfer restrictions and you may not be able to sell your original series C notes.

We will issue series C exchange notes as part of the exchange offer only after a timely receipt of your original series C notes, a properly completed and duly executed letter of transmittal and all other required documents. Therefore, if you want to tender your original series C notes, please allow sufficient time to ensure timely delivery. If we do not receive your original series C notes, letter of transmittal and other required documents by the expiration date of the exchange offer, we will not accept your original series C notes for exchange. We are under no duty to give notification of defects or irregularities with respect to the tenders of original series C notes for exchange. If there are defects or irregularities with respect to your tender of original series C notes, we will not accept your original series C notes for exchange. See "The Exchange Offer."

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FORWARD-LOOKING STATEMENTS

This prospectus contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as "may," "will," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "potential," "plan," "forecast" and similar terms. These statements represent our intentions, plans, expectations and beliefs and are subject to risks, uncertainties and other factors. Many of these factors are outside our control and could cause actual results to differ materially from such forward-looking statements. These factors include, among others:

• general economic, political and business conditions in the jurisdictions inside and outside of the United States in which our facilities are located;
• governmental, statutory, regulatory or administrative initiatives or ratemaking actions affecting us or the electric or gas utility, pipeline or power generation industries;
• weather effects on sales and revenues;
• general industry trends;
• increased competition in the power generation, electric utility or pipeline industries;
• fuel and power costs and availability;
• continued availability of accessible gas reserves;
• changes in business strategy, development plans or customer or vendor relationships;
• availability, term and deployment of capital;
• availability of qualified personnel;
• risks relating to nuclear generation;
• financial or regulatory accounting principles or policies imposed by the Public Company Accounting Oversight Board, the Financial Accounting Standards Board, the SEC, the FERC and similar entities with regulatory oversight; and
• other business or investment considerations that may be disclosed from time to time in our SEC filings or in other publicly disseminated written documents.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exclusive.

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USE OF PROCEEDS


    We will not receive any proceeds from the issuance of the series C exchange notes in the exchange offer. The series C exchange notes will evidence the same debt as the original series C notes tendered in exchange for series C exchange notes. Accordingly, the issuance of the series C exchange notes will not result in any change in our indebtedness.


    The net proceeds of the private placement of the original series C notes were approximately $446 million after deducting the initial purchasers' discount and expenses related to the offering of the original series C notes. We intend to use the net proceeds from the sale of the original series C notes for general corporate purposes. Pending such application, the net proceeds may be temporarily invested in short-term securities, money market funds, bank deposits or cash equivalents.

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THE EXCHANGE OFFER

Purpose of the Exchange Offer

On May 16, 2003, we privately placed the original series C notes in a transaction exempt from registration under the Securities Act. Accordingly, the original series C notes may not be reoffered, resold or otherwise transferred in the United States unless so registered or unless an exemption from the Securities Act registration requirements is available. Pursuant to a registration rights agreement with the initial purchasers of the original series C notes, we agreed, for the benefit of holders of the series C notes, to:

• prepare and file an exchange offer registration statement with the SEC with respect to a registered offer to exchange the original series C notes for a series of exchange notes that will be issued under the same indenture, in the same aggregate principal amount as and with terms that are substantially identical in all material respects to the original series C notes except that they will not contain terms with respect to transfer restrictions;
• use our reasonable best efforts to cause the exchange offer registration statement to become effective under the Securities Act within 270 days after the date on which we issued the original series C notes; and
• promptly after the exchange offer registration statement is declared effective, offer the series C exchange notes in exchange for surrender of the original series C notes.

We will be entitled to consummate the exchange offer on the expiration date provided that we have accepted all original series C notes previously validly tendered in accordance with the terms set forth in this prospectus and the applicable letter of transmittal.

In addition, under certain circumstances described below, we may be required to file a shelf registration statement to cover resales of the series C notes.

If we do not comply with certain of our obligations under the registration rights agreement, we must pay liquidated damages on the original series C notes in addition to the interest that is otherwise due on the series C notes. See "— Liquidated Damages." The purpose of the exchange offer is to fulfill our obligations with respect to the registration rights agreement.

If you are a broker-dealer that receives series C exchange notes for its own account in exchange for original series C notes, where you acquired such original series C notes as a result of market-making activities or other trading activities, you must acknowledge that you will deliver a prospectus in connection with any resale of such series C exchange notes. See "Plan of Distribution."

Terms of the Exchange


    Upon the terms and subject to the conditions contained in this prospectus and in the letters of transmittal that accompany this prospectus, we are offering to exchange $1,000 in principal amount of series C exchange notes for each $1,000 in principal amount of original series C notes. The terms of the series C exchange notes are substantially identical to the terms of the original series C notes except that the series C exchange notes will generally be freely transferable. The series C exchange notes will evidence the same debt as the original series C notes and will be entitled to the benefits of the indenture. Any original series C notes that remain outstanding after the consummation of the exchange offer, together with all series C exchange notes issued in connection with the exchange offer, will be treated as a single class of securities under the indenture. See "Description of Notes."

The exchange offer is not conditioned on any minimum aggregate principal amount of original series C notes being tendered for exchange.

Based on existing interpretations of the Securities Act by the staff of the SEC set forth in several no-action letters to third parties, and subject to the immediately following sentence, we believe that you may offer for resale, resell and otherwise transfer the series C exchange notes without further compliance with the registration and prospectus delivery provisions of the Securities Act. However, if

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you are an "affiliate" (within the meaning of the Securities Act) of ours or you intend to participate in the exchange offer for the purpose of distributing the series C exchange notes or you are a broker-dealer (within the meaning of the Securities Act) that acquired series C notes in a transaction other than as part of its market-making or other trading activities and who has arranged or has an understanding with any person to participate in the distribution of the series C exchange notes, you:

(1) will not be able to rely on the interpretations by the staff of the SEC set forth in the above-mentioned no-action letters;
(2) will not be able to tender your series C notes in the exchange offer; and
(3) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of your series C notes unless such sale or transfer is made pursuant to an exemption from such requirements.

Subject to exceptions for certain holders, to participate in the exchange offer you will be required to represent to us at the time of the consummation of the exchange offer, among other things, that (1) you are not an affiliate of ours; (2) any series C exchange notes to be received by you will be acquired in the ordinary course of your business; and (3) at the time of commencement of the exchange offer, you have no arrangement or understanding with any person to participate in the distribution (within the meaning of the Securities Act) of the series C notes. In addition, in connection with any resales of series C exchange notes, any broker-dealer who acquired series C exchange notes for its own account as a result of market-making activities or other trading activities must deliver a prospectus meeting the requirements of the Securities Act. The SEC has taken the position that such a broker-dealer may fulfill its prospectus delivery requirements with respect to the series C exchange notes (other than a resale of an unsold allotment from the initial sale of the original series C notes) with this prospectus. Under the registration rights agreement, we are required to allow a broker-dealer and other persons with similar prospectus delivery requirements, if any, to use this prospectus connection with the resale of such series C exchange notes for a period of time not less than 120 days following the consummation of the exchange offer. If you are a broker-dealer that receives series C exchange notes for its own account in exchange for original series C notes, where you acquired such original series C notes as a result of market-making activities or other trading activities, you must acknowledge that you will deliver a prospectus in connection with any resale of such series C exchange notes. See "Plan of Distribution."

You will not be required to pay brokerage commissions or fees or, subject to the instructions in the applicable letter of transmittal, transfer taxes relating to your exchange of original series C notes for series C exchange notes in the exchange offer.

Shelf Registration Statement

If:

• we are not permitted to effect the exchange offer because of any change in law or in applicable interpretations of such law by the staff of the SEC;
• the exchange offer is not consummated by the 40th day after the date on which the exchange offer registration statement was declared effective;
• any of the initial purchasers of the original series C notes so requests with respect to the original series C notes not eligible to be exchanged for series C exchange notes in the exchange offer and held by it following the consummation of exchange offer;
• any holder of series C notes (other than a broker-dealer electing to exchange original series C notes acquired for its own account as a result of market-making or other trading activities for exchange securities) is not eligible to participate in the exchange offer and any such holder so requests for any reason other than the failure by such holder to make a timely and valid tender in accordance with the terms of exchange offer; or
• any holder of series C notes (other than a broker-dealer electing to exchange original series C notes acquired for its own account as a result of market-making or other trading activities for

22

series C exchange notes) participates in the exchange offer but does not receive freely tradeable series C exchange notes on the date of the exchange and any such holder so requests for any reason other than the failure by such holder to make a timely and valid tender in accordance with the terms of exchange offer,

we will:

• as promptly as practicable prepare and file with the SEC a shelf registration statement relating to the offer and sale of series C notes that are not otherwise freely tradable; and
• use our reasonable best efforts to cause the shelf registration statement to be declared effective not later than the later to occur of the date that is 150 days after the date on which our obligation to file the shelf registration arises or 270 days after the date on which we issued the original series C notes; and
• use our reasonable best efforts to keep the shelf registration statement continuously effective until the earlier of two years from the date on which we issued the original series C notes (subject to extension under certain circumstances) and such shorter period ending when all the series C notes covered by the shelf registration statement have been sold pursuant to the shelf registration statement or are no longer restricted securities (as defined in Rule 144 under the Securities Act).

You will not be entitled, except if you were an initial purchaser of the original series C notes, to have your series C notes registered under the shelf registration statement, unless you agree in writing to be bound by the applicable provisions of the registration rights agreement. In order to sell your series C notes under the shelf registration statement, you generally must be named as a selling security holder in the related prospectus and must deliver a prospectus to purchasers. Consequently, you will be subject to the civil liability provisions under the Securities Act in connection with those sales and indemnification obligations under the registration rights agreements.

Liquidated Damages

A registration default will be deemed to have occurred if:

(1) the exchange offer registration statement is not declared effective within 270 days after the date on which we issued the original series C notes;
(2) the shelf registration statement is not declared effective by the later to occur of the date that is 150 days after the date on which our obligation to file the shelf registration arises or 270 days after the date on which we issued the original series C notes; or
(3) after either the exchange offer registration statement or the shelf registration statement is declared effective, such registration statement or the related prospectus thereafter ceases to be effective or usable (subject to certain exceptions) in connection with resales of original series C notes or series C exchange notes for the periods specified and in accordance with the registration rights agreement.

Additional interest will accrue on the series C notes subject to such registration default at a rate of 0.5% from and including the date on which any such registration default occurs to but excluding the date on which all such registration defaults have ceased to be continuing. In each case, such additional interest is payable in addition to any other interest payable from time to time with respect to the original series C notes and the series C exchange notes. The series C exchange notes will not contain any provisions regarding the payment of liquidated damages.

Expiration Date; Extensions; Termination; Amendments

The exchange offer expires on the expiration date. The expiration date is 5:00 p.m., New York City time, on July 11, 2003, unless we in our sole discretion extend the period during which the exchange offer is open, in which event the expiration date is the latest time and date on which the exchange offer, as so extended by us, expires. We reserve the right to extend the exchange offer at any

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time and from time to time prior to the expiration date by giving written notice to The Bank of New York, as the exchange agent, and by timely public announcement communicated in accordance with applicable law or regulation. During any extension of the exchange offer, all original series C notes previously tendered pursuant to the exchange offer and not validly withdrawn will remain subject to the exchange offer.

The exchange date will occur promptly after the expiration date. We expressly reserve the right to (i) terminate the exchange offer and not accept for exchange any original series C notes for any reason, including if any of the events set forth below under "— Conditions to the Exchange Offer" shall have occurred and shall not have been waived by us and (ii) amend the terms of the exchange offer in any manner, whether before or after any tender of the original series C notes. If any such termination or amendment occurs, we will notify the exchange agent in writing and will either issue a press release or give written notice to the holders of the original series C notes as promptly as practicable. Unless we terminate the exchange offer prior to 5:00 p.m., New York City time, on the expiration date, we will exchange the series C exchange notes for the original series C notes on the exchange date.

If we waive any material condition to the exchange offer, or amend the exchange offer in any other material respect, and if at the time that notice of such waiver or amendment is first published, sent or given to holders of original series C notes in the manner specified above, the exchange offer is scheduled to expire at any time earlier than the expiration of a period ending on the fifth business day from, and including, the date that such notice is first so published, sent or given, then the exchange offer will be extended until the expiration of such period of five business days.

This prospectus and the related letters of transmittal and other relevant materials will be mailed by us to record holders of original series C notes and will be furnished to brokers, banks and similar persons whose names, or the names of whose nominees, appear on the lists of holders for subsequent transmittal to beneficial owners of original series C notes.

How to Tender

The tender to us of original series C notes by you pursuant to one of the procedures set forth below will constitute an agreement between you and us in accordance with the terms and subject to the conditions set forth herein and in the applicable letter of transmittal.

General Procedures.    A holder of an original series C note may tender the same by (i) properly completing and signing the applicable letter of transmittal or a facsimile thereof (all references in this prospectus to the letter of transmittal shall be deemed to include a facsimile thereof) and delivering the same, together with the certificate or certificates representing the original series C notes being tendered and any required signature guarantees (or a timely confirmation of a book-entry transfer, which we refer to as a Book-Entry Confirmation, pursuant to the procedure described below), to the exchange agent at its address set forth on the back cover of this prospectus on or prior to the expiration date or (ii) complying with the guaranteed delivery procedures described below.

If tendered original series C notes are registered in the name of the signer of the letter of transmittal and the series C exchange notes to be issued in exchange therefor are to be issued (and any untendered original series C notes are to be reissued) in the name of the registered holder, the signature of such signer need not be guaranteed. In any other case, the tendered original series C notes must be endorsed or accompanied by written instruments of transfer in form satisfactory to us and duly executed by the registered holder and the signature on the endorsement or instrument of transfer must be guaranteed by a firm, which we refer to as an Eligible Institution, that is a member of a recognized signature guarantee medallion program, which we refer to as an Eligible Program, within the meaning of Rule 17Ad-15 under the Exchange Act. If the series C exchange notes and/or original series C notes not exchanged are to be delivered to an address other than that of the registered holder appearing on the note register for the original series C notes, the signature on the letter of transmittal must be guaranteed by an Eligible Institution.

Any beneficial owner whose original series C notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and who wishes to tender original series C notes

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should contact such holder promptly and instruct such holder to tender original series C notes on such beneficial owner's behalf. If such beneficial owner wishes to tender such original series C notes himself, such beneficial owner must, prior to completing and executing the letter of transmittal and delivering such original series C notes, either make appropriate arrangements to register ownership of the original series C notes in such beneficial owner's name or follow the procedures described in the immediately preceding paragraph. The transfer of record ownership may take considerable time.

Book-Entry Transfer.    The exchange agent will make a request to establish an account with respect to the original series C notes at The Depository Trust Company, which we refer to as the Book-Entry Transfer Facility, for purposes of the exchange offer within two business days after receipt of this prospectus, and any financial institution that is a participant in the Book-Entry Transfer Facility's systems may make book-entry delivery of original series C notes by causing the Book-Entry Transfer Facility to transfer such original series C notes into the exchange agent's account at the Book-Entry Transfer Facility in accordance with the Book-Entry Transfer Facility's procedures for transfer. However, although delivery of original series C notes may be effected through book-entry transfer at the Book-Entry Transfer Facility, the letter of transmittal, with any required signature guarantees and any other required documents, must, in any case, be transmitted to and received by the exchange agent at the address specified on the back cover page of this prospectus on or prior to the expiration date or the guaranteed delivery procedures described below must be complied with.

The method of delivery of original series C notes and all other documents is at your election and risk. If sent by mail, we recommend that you use registered mail, return receipt requested, obtain proper insurance, and complete the mailing sufficiently in advance of the expiration date to permit delivery to the exchange agent on or before the expiration date.

Guaranteed Delivery Procedures.    If a holder desires to accept the exchange offer and time will not permit a letter of transmittal or original series C notes to reach the exchange agent before the expiration date, a tender may be effected if the exchange agent has received at its office listed on the back cover hereof on or prior to the expiration date a letter, telegram or facsimile transmission from an Eligible Institution setting forth the name and address of the tendering holder, the names in which the original series C notes are registered, the principal amount of the original series C notes and, if possible, the certificate numbers of the original series C notes to be tendered, and stating that the tender is being made thereby and guaranteeing that within three New York Stock Exchange trading days after the date of execution of such letter, telegram or facsimile transmission by the Eligible Institution, the original series C notes, in proper form for transfer, will be delivered by such Eligible Institution together with a properly completed and duly executed letter of transmittal (and any other required documents). Unless original series C notes being tendered by the above-described method (or a timely Book-Entry Confirmation) are deposited with the exchange agent within the time period set forth above (accompanied or preceded by a properly completed letter of transmittal and any other required documents), we may, at our option, reject the tender. Copies of a Notice of Guaranteed Delivery which may be used by Eligible Institutions for the purposes described in this paragraph are being delivered with this prospectus and the related letter of transmittal.

A tender will be deemed to have been received as of the date when the tendering holder's properly completed and duly signed letter of transmittal accompanied by the original series C notes (or a timely Book-Entry Confirmation) is received by the exchange agent. Issuances of series C exchange notes in exchange for original series C notes tendered pursuant to a Notice of Guaranteed Delivery or letter, telegram or facsimile transmission to similar effect (as provided above) by an Eligible Institution will be made only against deposit of the letter of transmittal (and any other required documents) and the tendered original series C notes (or a timely Book-Entry Confirmation).

All questions as to the validity, form, eligibility (including time of receipt) and acceptance for exchange of any tender of original series C notes will be determined by us and our determination will be final and binding. We reserve the absolute right to reject any or all tenders not in proper form or the acceptances for exchange of which may, in the opinion of our counsel, be unlawful. We also reserve the absolute right to waive any of the conditions of the exchange offer or any defect or irregularities in tenders of any particular holder whether or not similar defects or irregularities are

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waived in the case of other holders. None of us, the exchange agent or any other person will be under any duty to give notification of any defects or irregularities in tenders or shall incur any liability for failure to give any such notification. Our interpretation of the terms and conditions of the exchange offer (including the letters of transmittal and the instructions thereto) will be final and binding.

Terms and Conditions of the Letters of Transmittal

The letters of transmittal contain, among other things, the following terms and conditions, which are part of the exchange offer.

The party tendering original series C notes for exchange, whom we refer to as the Transferor, exchanges, assigns and transfers the original series C notes to us and irrevocably constitutes and appoints the exchange agent as the Transferor's agent and attorney-in-fact to cause the original series C notes to be assigned, transferred and exchanged. The Transferor represents and warrants that it has full power and authority to tender, exchange, assign and transfer the original series C notes and to acquire series C exchange notes issuable upon the exchange of such tendered original series C notes, and that, when the same are accepted for exchange, we will acquire good and unencumbered title to the tendered original series C notes, free and clear of all liens, restrictions, charges and encumbrances and not subject to any adverse claim. The Transferor also warrants that it will, upon request, execute and deliver any additional documents deemed by us to be necessary or desirable to complete the exchange, assignment and transfer of tendered original series C notes. The Transferor further agrees that acceptance of any tendered original series C notes by us and the issuance of series C exchange notes in exchange therefor shall constitute performance in full by us of our obligations under the registration rights agreement and that we shall have no further obligations or liabilities thereunder (except in certain limited circumstances). All authority conferred by the Transferor will survive the death or incapacity of the Transferor and every obligation of the Transferor shall be binding upon the heirs, legal representatives, successors, assigns, executors and administrators of such Transferor.

See "— Terms of the Exchange."

Withdrawal Rights

Original series C notes tendered pursuant to the exchange offer may be withdrawn at any time prior to the expiration date. For a withdrawal to be effective, a written or facsimile transmission notice of withdrawal must be timely received by the exchange agent at its address set forth on the back cover of this prospectus. Any such notice of withdrawal must specify the person named in the letter of transmittal as having tendered original series C notes to be withdrawn, the certificate numbers of original series C notes to be withdrawn, the principal amount of original series C notes to be withdrawn (which must be an authorized denomination), a statement that such holder is withdrawing his election to have such original series C notes exchanged, and the name of the registered holder of such original series C notes, and must be signed by the holder in the same manner as the original signature on the letter of transmittal (including any required signature guarantees) or be accompanied by evidence satisfactory to us that the person withdrawing the tender has succeeded to the beneficial ownership of the original series C notes being withdrawn. The exchange agent will return the properly withdrawn original series C notes promptly following receipt of notice of withdrawal. All questions as to the validity of notices of withdrawals, including time of receipt, will be determined by us, and our determination will be final and binding on all parties.

Acceptance of Original Notes for Exchange; Delivery of Exchange Notes

Upon the terms and subject to the conditions of the exchange offer, the acceptance for exchange of original series C notes validly tendered and not withdrawn and the issuance of the series C exchange notes will be made on the exchange date. For the purposes of the exchange offer, we shall be deemed to have accepted for exchange validly tendered original series C notes when, as and if we have given written notice thereof to the exchange agent.

The exchange agent will act as agent for the tendering holders of original series C notes for the purposes of receiving series C exchange notes from us and causing the original series C notes to be

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assigned, transferred and exchanged. Upon the terms and subject to the conditions of the exchange offer, delivery of series C exchange notes to be issued in exchange for accepted original series C notes will be made by the exchange agent promptly after acceptance of the tendered original series C notes. Original series C notes not accepted for exchange by us will be returned without expense to the tendering holders (or in the case of original series C notes tendered by book-entry transfer into the exchange agent's account at the Book-Entry Transfer Facility pursuant to the procedures described above, such non-exchanged original series C notes will be credited to an account maintained with such Book-Entry Transfer Facility) promptly following the expiration date or, if we terminate the exchange offer prior to the expiration date, promptly after the exchange offer is so terminated.

Conditions to the Exchange Offer

We are not required to accept for exchange, or to issue series C exchange notes in exchange for, any outstanding original series C notes. We may terminate or extend the exchange offer by oral or written notice to the exchange agent and by timely public announcement communicated in accordance with applicable law or regulation, if:

• any federal law, statute, rule, regulation or interpretation of the staff of the SEC has been proposed, adopted or enacted that, in our judgment, might impair our ability to proceed with the exchange offer or otherwise make it inadvisable to proceed with the exchange offer;
• an action or proceeding has been instituted or threatened in any court or by any governmental agency that, in our judgement might impair our ability to proceed with the exchange offer or otherwise make it inadvisable to proceed with the exchange offer;
• there has occurred a material adverse development in any existing action or proceeding that might impair our ability to proceed with the exchange offer or otherwise make it inadvisable to proceed with the exchange offer;
• any stop order is threatened or in effect with respect to the registration statement of which this prospectus is a part or the qualification of the indenture under the Trust Indenture Act of 1939;
• all governmental approvals that we deem necessary for the consummation of the exchange offer have not been obtained;
• there is a change in the current interpretation by the staff of the SEC which permits holders who have made the required representations to us to resell, offer for resale, or otherwise transfer series C exchange notes issued in the exchange offer without registration of the series C exchange notes and delivery of a prospectus; or
• a material adverse change shall have occurred in our business, condition, operations or prospects.

The foregoing conditions are for our sole benefit and may be asserted by us with respect to all or any portion of the exchange offer regardless of the circumstances (including any action or inaction by us) giving rise to such condition or may be waived by us in whole or in part at any time or from time to time in our sole discretion. The failure by us at any time to exercise any of the foregoing rights will not be deemed a waiver of any such right, and each right will be deemed an ongoing right which may be asserted at any time or from time to time. In addition, we have reserved the right, notwithstanding the satisfaction of each of the foregoing conditions, to terminate or amend the exchange offer.

Any determination by us concerning the fulfillment or non-fulfillment of any conditions will be final and binding upon all parties.

Exchange Agent

The Bank of New York has been appointed as the exchange agent for the exchange offer. Letters of transmittal must be addressed to the exchange agent at its address set forth on the back cover page

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of this prospectus. Delivery to an address other than as set forth herein, or transmissions of instructions via a facsimile or telex number other than the ones set forth herein, will not constitute a valid delivery.

Solicitation of Tenders; Expenses

We have not retained any dealer-manager or similar agent in connection with the exchange offer and will not make any payments to brokers, dealers or others for soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and will reimburse it for reasonable out-of-pocket expenses in connection therewith. We will also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding tenders for their customers. The expenses to be incurred in connection with the exchange offer, including the fees and expenses of the exchange agent and printing, accounting and legal fees, will be paid by us and are estimated at approximately $250,000.

No dealer, salesperson or other individual has been authorized to give any information or to make any representations not contained in this prospectus in connection with the exchange offer. If given or made, such information or representations must not be relied upon as having been authorized by us. Neither the delivery of this prospectus nor any exchange made hereunder shall, under any circumstances, create any implication that there has been no change in our affairs since the respective dates as of which information is given herein.

The exchange offer is not being made to (nor will tenders be accepted from or on behalf of) holders of original series C notes in any jurisdiction in which the making of the exchange offer or the acceptance thereof would not be in compliance with the laws of such jurisdiction. However, we may, at our discretion, take such action as we may deem necessary to make the exchange offer in any such jurisdiction and extend the exchange offer to holders of original series C notes in such jurisdiction. In any jurisdiction the securities laws or blue sky laws of which require the exchange offer to be made by a licensed broker or dealer, the exchange offer is being made on behalf of us by one or more registered brokers or dealers which are licensed under the laws of such jurisdiction.

Appraisal Rights

You will not have appraisal rights in connection with the exchange offer.

Federal Income Tax Consequences

The exchange of original series C notes for series C exchange notes will not be a taxable exchange for U.S. federal income tax purposes, and holders will not recognize any taxable gain or loss or any interest income as a result of such exchange. See "Certain United States Federal Income Tax Considerations."

Other

Participation in the exchange offer is voluntary and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decisions on what action to take.

As a result of the making of, and upon acceptance for exchange of all validly tendered original series C notes pursuant to the terms of this exchange offer, we will have fulfilled a covenant contained in the terms of the original series C notes and the registration rights agreement. Holders of the original series C notes who do not tender their original series C notes in the exchange offer will continue to hold such original series C notes and will be entitled to all the rights, and limitations applicable thereto, under the indenture, except for any such rights under the registration rights agreement which by their terms terminate or cease to have further effect as a result of the making of this exchange offer. See "Description of Notes." All untendered original series C notes will continue

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to be subject to the restriction on transfer set forth in the indenture. To the extent that original series C notes are tendered and accepted in the exchange offer, the trading market, if any, for the original series C notes could be adversely affected. See "Risk Factors — Your ability to sell your original series C notes may be significantly more limited and the price at which you may be able to sell your original series C notes may be significantly lower if you do not exchange them for registered series C exchange notes in the exchange offer."

We may in the future seek to acquire untendered original series C notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plan to acquire any original series C notes which are not tendered in the exchange offer.

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CAPITALIZATION

The following table sets forth our consolidated capitalization at March 31, 2003 and our pro forma consolidated capitalization at March 31, 2003 as if all of the original series C notes had been issued on March 31, 2003. The table should be read in conjunction with our historical consolidated financial statements and the notes thereto appearing elsewhere in this prospectus.


  March 31, 2003
  Actual Pro Forma
Adjustments		 Pro Forma
  (In thousands)
Indebtedness:
Subsidiary short-term debt $ 70,932   $ —   $ 70,932  
Parent company long-term debt(1)   2,540,756     449,285 (2)    2,990,041  
Subsidiary long-term debt(3)(4)   7,381,152           7,381,152  
Total consolidated indebtedness   9,992,840     449,285     10,442,125  
Parent company-obligated mandatorily redeemable preferred securities of subsidiary trusts held by
Berkshire Hathaway(5)		   1,727,772           1,727,772  
Parent company-obligated mandatorily redeemable preferred securities of subsidiary trusts held by others   336,163           336,163  
Preferred securities of subsidiaries   93,028           93,028  
Shareholders' equity:
Zero-coupon convertible preferred stock — authorized 50,000 shares, no par value, 41,263 shares issued and outstanding   —           —  
Common stock — authorized 60,000 shares, no par value, 9,281 shares issued and outstanding   —           —  
Additional paid-in capital   1,956,509           1,956,509  
Retained earnings   714,645           714,645  
Accumulated other comprehensive loss   (269,149 )          (269,149 ) 
Total shareholders' equity   2,402,005     —     2,402,005  
Total capitalization $ 14,551,808   $ 449,285   $ 15,001,093  
(1) Includes approximately $215 million current portion of parent company long-term debt.
(2) Represents the series C notes.
(3) Represents debt for which the repayment obligation is at our subsidiary level and that is non-recourse to us except as it relates to our guarantee of approximately $51 million of the Cordova Funding Corporation Senior Secured Bonds, our guarantee of approximately $138 million for the Salton Sea Funding Series F Bonds, our letters of credit of approximately $42 million for our geothermal facilities located on the island of Leyte in the Philippines, and our completion guarantee as it potentially related to Kern River's $875 million construction loan facility, of which approximately $805 million was drawn as of March 31, 2003. Kern River entered into this credit facility in 2002 to finance the construction of its 2003 Expansion Project. The credit facility was canceled and our completion guarantee in favor of the lenders as part of the credit facility terminated upon completion of the 2003 Expansion Project on May 1, 2003.
(4) Includes approximately $149 million current portion of subsidiary long-term debt.
(5) Includes $150 million which is due August 31, 2003.

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

The following tables set forth selected historical consolidated financial and operating data, which should be read in conjunction with our financial statements and the related notes to those statements included in this prospectus and with "Management's Discussion and Analysis of Financial Condition and Results of Operations" appearing elsewhere in this prospectus. The selected consolidated data as of and for each of the five years in the period ended December 31, 2002 have been derived from our audited historical consolidated financial statements. The selected consolidated data as of March 31, 2003 and for the three-month periods ended March 31, 2003 and 2002 have been derived from our unaudited historical consolidated financial statements and reflect all adjustments (consisting of normal recurring accruals) necessary in the opinion of our management for a fair presentation of such data. All amounts (except for ratios) are presented in thousands.


        Our Predecessor
  Year Ended
December 31,		 March 14,
2000 through
December 31,
2000(3)		 January 1,
2000 through
March 13,
2000(4)		 Year Ended
December 31,
  2002(1) 2001(2) 1999(5) 1998(6)
STATEMENT OF OPERATIONS DATA:
Operating revenue $ 4,794,010   $ 4,696,781   $ 3,918,100   $ 1,056,365   $ 4,086,622   $ 2,475,181  
Total revenue   4,968,139     4,972,980     4,012,982     1,075,849     4,368,501     2,602,686  
Cost of sales and operating expenses   3,189,229     3,517,600     3,099,023     801,587     3,103,160     1,649,919  
Depreciation and amortization   525,902     538,702     383,351     97,278     427,690     333,422  
Interest expense, net of capitalized interest   609,910     412,794     311,404     85,814     426,173     347,292  
Provision for income taxes   99,588     250,064     53,277     31,008     93,475     93,265  
Minority interest and preferred
dividends		   163,467     106,547     84,670     8,850     46,923     41,276  
Income before extraordinary item and cumulative effect of change in accounting principle   380,043     147,273     81,257     51,312     216,671     137,512  
Extraordinary item, net of tax   —     —     —     —     (49,441 )    (7,146 ) 
Cumulative effect of change in accounting principle, net of tax   —     (4,604 )    —     —     —     (3,363 ) 
Net income available to common and preferred stockholders   380,043     142,669     81,257     51,312     167,230     127,003  
OTHER FINANCIAL DATA:
Capital expenditures relating to operating projects $ 542,615   $ 398,165   $ 301,948   $ 44,355   $ 360,898   $ 227,071  
Ratio of earnings to fixed charges(7)   1.9 x    1.8 x    1.3 x    1.7 x    1.6 x    1.5 x 
Net cash flows from operating activities   757,726     846,998     246,407     171,083     554,959     361,546  
Net cash flows from investing activities   (2,907,811 )    (238,544 )    (2,389,160 )    (54,874 )    (1,960,820 )    (1,007,780 ) 
Net cash flows from financing activities   2,555,234     (258,467 )    1,878,849     (128,501 )    115,875     797,338  

  Three Months Ended
March 31,
  2003 2002
STATEMENT OF OPERATIONS DATA:
Operating revenue   1,562,834     1,041,752  
Total revenue   1,603,954     1,069,577  
Cost of sales and operating expenses   1,029,243     688,950  
Depreciation and amortization   141,849     126,244  
Interest expense, net of capitalized interest   171,313     134,653  
Provision for income taxes   73,000     29,130  
Minority interest and preferred dividends   57,913     25,851  
Net income available to common and preferred stockholders   130,636     64,749  
OTHER FINANCIAL DATA:
Capital expenditures relating to operating projects   133,845     95,673  
Ratio of earnings to fixed charges(7)   2.3 x    1.8 x 
Net cash flows from operating activities   385,793     182,622  
Net cash flows from investing activities   (444,000 )    (886,690 ) 
Net cash flows from financing activities   73,549     1,029,196  

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  As of
March 31,
2003		       Our Predecessor
  As of December 31,
  2002 2001 2000 1999 1998
BALANCE SHEET DATA:      
Properties, plants and equipment, net $ 10,135,056   $ 9,898,796   $ 6,537,371   $ 5,348,647   $ 5,463,329   $ 4,236,039  
Total assets   18,408,960     18,016,455     12,626,652     11,610,939     10,766,352     9,103,524  
Short-term debt   70,932     79,782     256,012     261,656     379,523     —  
Current portion of long-term debt   364,358     470,213     317,180     438,978     235,202     381,491  
Parent company debt   2,325,756     2,324,456     1,834,498     1,829,971     1,856,318     2,645,991  
Subsidiary and project debt   7,231,794     7,077,087     4,754,811     3,388,696     3,642,703     2,712,319  
Total liabilities   13,765,764     13,478,006     9,778,757     8,911,349     8,978,924     7,598,040  
Parent company-obligated mandatorily Redeemable preferred securities held by Berkshire Hathaway   1,727,772     1,727,772     454,772     454,772     —     —  
Parent company-obligated mandatorily redeemable preferred securities held by others    336,163     335,640     333,379     331,751     450,000     553,930  
Total shareholders' equity   2,402,005     2,294,283     1,708,167     1,576,401     994,588     827,053  
(1) Reflects the acquisitions of Kern River on March 27, 2002 and Northern Natural Gas on August 16, 2002.
(2) Reflects the Yorkshire Swap on September 21, 2001 and includes $15.2 million of non-recurring net income related to the sale of the Northern Electric electricity and gas supply business, the sale of the Telephone Flat Project, the sale of Western States Geothermal, the transfer of Bali Energy Ltd. shares, and the TPL asset valuation impairment charge.
(3) Reflects the Teton Transaction on March 14, 2000.
(4) Includes $7.6 million of non-recurring expenses for the costs related to the Teton Transaction on March 14, 2000.
(5) Reflects our acquisition of MidAmerican Energy on March 12, 1999, our disposition of the Coso Joint Ventures on February 26, 1999, and our disposition of a 50% ownership interest in CE Gen on March 3, 1999 and includes $81.5 million of non-recurring net income related to the settlement of political risk insurance proceeds related to our investment in Indonesia, gains on sales of shares of McLeodUSA, our disposition of the Coso Joint Ventures, our disposition of a 50% ownership interest of CE Gen, CE Electric UK restructuring charges and transaction costs related to our acquisition by a private investor group.
(6) Reflects the acquisition of Kiewit Diversified Group on January 2, 1998.
(7) For purposes of computing the ratio of earnings to fixed charges, earnings are divided by fixed charges. Earnings represent the aggregate of (a) our pre-tax income and (b) fixed charges, less capitalized interest. Fixed charges represent interest (whether expensed or capitalized), amortization of deferred financing and bank fees, and the estimated interest component of rentals.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management's discussion and analysis of certain significant factors which have affected the financial condition and results of operations of MidAmerican Energy Holdings Company, or MEHC, during the periods included in the accompanying statements of operations. This discussion should be read in conjunction with "Selected Consolidated Financial and Operating Data" and MEHC's historical financial statements and the notes to those statements included elsewhere in this prospectus.

General

MEHC is a United States-based privately owned global energy company with publicly held fixed income securities that generates, distributes and supplies energy to utilities, government entities, retail customers and other customers located throughout the world. Through its subsidiaries, its operations are organized and managed on seven distinct platforms: MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK (which includes Northern Electric and Yorkshire Electricity), CalEnergy Generation – Domestic, CalEnergy Generation – Foreign and HomeServices. MEHC accounts for each of these platforms as a separate operating segment. For information regarding these segments, see note 8 to the unaudited consolidated financial statements for the three months ended March 31, 2003 and note 21 to the consolidated financial statements for the year ended December 31, 2002 included in this prospectus.

As a result of the acquisitions of Kern River and Northern Natural Gas, the Yorkshire Swap, and the acquisition by a private investor group on March 14, 2000, MEHC's future results will differ from its historical results.

2002 Acquisitions

Kern River

In March 2002, MEHC acquired Kern River for $419.7 million, net of cash acquired of $7.7 million and a working capital adjustment. Kern River's principal asset is an interstate natural gas pipeline system extending from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. In connection with the acquisition of Kern River, MEHC issued $323.0 million of 11% company-obligated mandatorily redeemable preferred securities of subsidiary trust due March 12, 2012 with scheduled principal payments beginning in 2005 and $127.0 million of no par, zero coupon convertible preferred stock to Berkshire Hathaway.

Northern Natural Gas

In August 2002, MEHC acquired Northern Natural Gas for $882.7 million, net of cash acquired of $1.4 million and a working capital adjustment. Northern Natural Gas owns a 16,600-mile interstate natural gas pipeline extending from southwest Texas to the upper Midwest region of the United States with a design capacity of 4.4 Bcf of natural gas per day. Northern Natural Gas also operates three natural gas storage facilities and two liquefied natural gas peaking units with a total storage capacity of 59 Bcf and peak delivery capability of over 1.3 Bcf of natural gas per day. Northern Natural Gas accesses natural gas supply from many of the larger producing regions in North America, including the Rocky Mountains, Hugoton, Permian, Anadarko and Western Canadian basins. The pipeline system provides transportation and storage services to utilities, municipalities, other pipeline companies, gas marketers and industrial and commercial users. MEHC used the proceeds from a $950.0 million investment in its subsidiary trust's preferred securities by Berkshire Hathaway to finance the acquisition.

HomeServices' 2002 Acquisitions

In 2002, HomeServices separately acquired three real estate companies for an aggregate purchase price of approximately $106.1 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2001, these real estate companies had combined

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revenue of approximately $356.0 million on 42,000 closed sides representing $13.7 billion of sales volume. Additionally, HomeServices is obligated to pay a maximum earnout of $18.5 million based on 2002 financial performance measures. These purchases were financed using HomeServices' internally generated cash flows, revolving credit facility and $40.0 million from MEHC, which was contributed to HomeServices as equity.

Critical Accounting Policies

The preparation of financial statements and related documents in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Note 2 to the consolidated financial statements for the year ended December 31, 2002 included in this prospectus describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Estimates are used for, but not limited to, the accounting for revenue, the effects of certain types of regulation, impairment of long-lived assets, and contingent liabilities. Actual results could differ from these estimates. The following critical accounting policies are impacted significantly by judgments, assumptions and estimates used in the preparation of the consolidated financial statements.

Accounting for the Effects of Certain Types of Regulation

MidAmerican Energy, Kern River and Northern Natural Gas prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards, or SFAS, No. 71, or SFAS 71, which differs in certain respects from the application of generally accepted accounting principles by non-regulated businesses. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, MidAmerican Energy, Kern River and Northern Natural Gas have deferred certain costs, which will be amortized over various future periods. To the extent that collection of such costs or payment of such obligations is no longer probable as a result of changes in regulation, the associated regulatory asset or liability is charged or credited to income.

A possible consequence of deregulation of the regulated energy industry is that SFAS 71 may no longer apply. If portions of MEHC's subsidiaries' regulated energy operations no longer meet the criteria of SFAS 71, MEHC could be required to write off the related regulatory assets and liabilities from its balance sheet, and thus a material adjustment to earnings in that period could result if regulatory assets or liabilities are not recovered in transition provisions of any deregulation legislation.

MEHC continues to evaluate the applicability of SFAS 71 to its regulated energy operations and the recoverability of these assets and liabilities through rates as there are on-going changes in the regulatory and economic environment.

Impairment of Long-Lived Assets

MEHC's long-lived assets consist primarily of properties, plants and equipment. Depreciation is computed using the straight-line method based on economic lives or regulatory mandated recovery periods. MEHC believes the useful lives assigned to the depreciable assets, which generally range from 3 to 87 years, are reasonable.

MEHC periodically evaluates long-lived assets, including properties, plants and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Upon the occurrence of a triggering event, the carrying amount of a long-lived asset is reviewed to assess whether the recoverable amount has declined below its carrying amount. The recoverable amount is the estimated net future cash flows that MEHC expects to recover from the future use of the asset, undiscounted and without interest, plus the asset's residual value on disposal. Where the recoverable amount of the long-lived asset is less than the carrying value, an impairment loss would be recognized to write down the asset to its fair value that is based on discounted estimated cash flows from the future use of the asset.

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The estimate of cash flows arising from future use of the asset that are used in the impairment analysis requires judgment regarding what MEHC would expect to recover from future use of the asset. Any changes in the estimates of cash flows arising from future use of the asset or the residual value of the asset on disposal based on changes in the market conditions, changes in the use of the asset, management's plans, the determination of the useful life of the asset and technology changes in the industry could significantly change the calculation of the fair value or recoverable amount of the asset and the resulting impairment loss, which could significantly affect the results of operations. The determination of whether impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. An impairment analysis of generating facilities requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the facilities. A resulting impairment loss is highly dependent on these underlying assumptions.

Contingent Liabilities

MEHC establishes reserves for estimated loss contingencies when it is management's assessment that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in operations in the period in which different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Reserves for contingent liabilities are based upon management's assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcomes of any matters. Should the outcomes differ from the assumptions and estimates, revisions to the estimated reserves for contingent liabilities would be required.

Revenue Recognition

Revenue is recorded based upon services rendered and electricity, gas and steam delivered, distributed or supplied to the end of the period. MEHC records unbilled revenue representing the estimated amounts customers will be billed for services rendered between the meter reading dates in a particular month and the end of that month. The unbilled revenue estimate is reversed in the following month. To the extent the estimated amount differs from the actual amount subsequently billed, revenue will be affected.

Where there is an over recovery of United Kingdom distribution business revenue against the maximum regulated amount, revenue is deferred in an amount equivalent to the over recovered amount. The deferred amount is deducted from revenue and included in other liabilities. Where there is an under recovery, no anticipation of any potential future recovery is made.

Revenue from the transportation and storage of gas are recognized based on contractual terms and the related volumes. Kern River and Northern Natural Gas are subject to the FERC's regulations and, accordingly, certain revenue collected may be subject to possible refunds upon final orders in pending rate cases. Kern River and Northern Natural Gas record rate refund liabilities considering their regulatory proceedings and other third party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks.

Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when title has transferred from seller to buyer. Title fee revenue from real estate transactions and related amounts due to the title insurer are recognized at the closing, which is when consideration is received. Fees related to loan originations are recognized at the closing, which is when services have been provided and consideration is received.

Results of Operations for the Three-Month Periods Ended March 31, 2003 and 2002

Operating revenue for the three-month period ended March 31, 2003 increased $521.0 million or 50.0% to $1,562.8 million from $1,041.8 million for the same period in 2002.

MidAmerican Energy operating revenue for the three-month period ended March 31, 2003 increased $240.9 million or 41.9% to $815.9 million from $575.0 million for the same period in 2002. The increase was primarily due to an increase in gas revenues of $225.6 million to $479.8 million for the three-month period ended March 31, 2003, resulting from higher gas prices and, to a lesser degree, higher volumes.

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Kern River operating revenue for the three-month period ended March 31, 2003, increased $36.8 million to $39.0 million. Operating revenue in 2002 was recorded for Kern River beginning on March 27, 2002, the acquisition date.

Northern Natural Gas operating revenue for the three-month period ended March 31, 2003, was $170.0 million. As Northern Natural Gas was acquired on August 16, 2002, there was no revenue recorded during the three-month period ended March 31, 2002.

HomeServices operating revenue for the three-month period ended March 31, 2003, increased $83.4 million or 47.8% to $258.0 million from $174.6 million for the same period in 2002. The increase was due to the impact of 2002 acquisitions totaling $72.0 million and growth from existing operations, reflecting higher transaction volumes and average home sales prices.

Income on equity investments for the three-month period ended March 31, 2003 decreased $6.6 million or 46.8% to $7.5 million from $14.1 million for the same period in 2002. The decrease was primarily due to a common stock distribution from an energy investment fund in 2002.

Interest and dividend income for the three-month period ended March 31, 2003 increased $5.5 million or 65.5% to $13.9 million from $8.4 million for the same period in 2002. The increase is primarily due to dividends received on the investment in The Williams Companies, Inc., or Williams, preferred stock.

Other income for the three-month period ended March 31, 2003 increased $14.4 million to $19.8 million from $5.4 million for the same period in 2002. The increase was primarily due to the allowance for equity funds used during construction at Kern River and MidAmerican Energy.

Cost of sales for the three-month period ended March 31, 2003 increased $263.5 million or 64.4% to $672.8 million from $409.3 million for the same period in 2002. MidAmerican Energy's cost of sales increased $233.4 million due primarily to increased gas prices and the restructuring of the Cooper Nuclear Station, or Cooper, contract which increased cost of sales and decreased operating expenses. HomeServices' cost of sales increased $57.0 million due to the prior year acquisitions and higher commission expense on incremental sales at existing business units.

Operating expenses for the three-month period ended March 31, 2003 increased $76.8 million or 27.5% to $356.5 million from $279.7 million for the same period in 2002. The increase was primarily due to Northern Natural Gas operating expenses of $61.5 million and increased operating expenses at Kern River, due to the inclusion of operations for the entire quarter, of $10.1 million, partially offset by MidAmerican Energy's operating expenses decrease of $15.5 million, primarily due to the restructuring of the Cooper contract.

Depreciation and amortization for the three-month period ended March 31, 2003 increased $15.6 million or 12.4% to $141.8 million from $126.2 million for the same period in 2002. This was primarily due to depreciation of $11.3 million at Northern Natural Gas and increased depreciation of $4.4 million at Kern River.

Interest expense for the three-month period ended March 31, 2003 increased $45.5 million or 32.2% to $186.8 million from $141.3 million for the same period in 2002. The increase was primarily due to $20.5 million increased interest expense at Kern River due to the inclusion of operations for the entire quarter and additional borrowings for the expansion project, $14.7 million due to the acquisition of Northern Natural Gas and additional interest expense totaling $9.7 million on MEHC's $700 million debt issuance in October 2002.

Capitalized interest for the three-month period ended March 31, 2003 increased $8.9 million to $15.5 million from $6.6 million for same period in 2002. The increase is primarily due to the capitalization of interest on the Kern River expansion project partially offset by the discontinuance of capitalizing interest at the Zinc Recovery Project.

The income tax provision for the three-month period ended March 31, 2003 increased $43.9 million to $73.0 million from $29.1 million for the same period in 2002. The effective tax rate for the three-month period ended March 31, 2003 increased to 27.9% from 24.3% for the same period in 2002. The increase in the effective rate was due to higher income at segments with higher tax rates.

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Minority interest and preferred dividends for the three-month period ended March 31, 2003 increased $32.0 million to $57.9 million from $25.9 million for the same period in 2002. The increase was primarily due to the issuances of $323.0 million and $950.0 million of 11% trust preferred securities in March 2002 and August 2002, respectively.

Net income available to common and preferred stockholders for the three-month period ended March 31, 2003 increased $65.9 million to $130.6 million from $64.7 million for the same period in 2002.

Results of Operations for the Year Ended December 31, 2002 and the Year Ended December 31, 2001

Operating revenue for the year ended December 31, 2002 increased $97.2 million or 2.1% to $4,794.0 million from $4,696.8 million for the same period in 2001.

CE Electric UK operating revenue for the year ended December 31, 2002 decreased $648.6 million or 44.9% to $795.4 million from $1,444.0 million for the same period in 2001, primarily due to the sale of the supply business in 2001 partially offset by the acquisition of Yorkshire Electric in September 2001 and changes in the exchange rate. CE Electric UK distributed 41,157 GWh of electricity in the year ended December 31, 2002, compared with 23,770 GWh of electricity in the same period in 2001. The increase in electricity distributed is primarily due to the acquisition of Yorkshire distribution.

MidAmerican Energy operating revenue for the year ended December 31, 2002 decreased $147.8 million or 6.2% to $2,240.9 million from $2,388.7 million for the same period in 2001. MidAmerican Energy electric retail sales increased for the year ended December 31, 2002 from the same period in 2001 due primarily to higher temperatures in 2002, primarily in the third quarter of 2002. Regulated and non-regulated gas revenue decreased due to lower prices for gas purchased passed directly to the customer.

Kern River operating revenue, from its date of acquisition, was $127.3 million. Kern River transported 285,848,285 MMBtus during the period since MEHC acquired Kern River on March 27, 2002 through December 31, 2002.

Northern Natural Gas operating revenue, from its date of acquisition, was $176.9 million. Northern Natural Gas transported 416,272,813 MMBtus since MEHC acquired Northern Natural Gas on August 16, 2002 through December 31, 2002.

CalEnergy Generation – Domestic operating revenue for the year ended December 31, 2002 increased $1.2 million or 3.2% to $38.5 million from $37.3 million for the same period in 2001.

CalEnergy Generation – Foreign operating revenue for the year ended December 31, 2002 increased $122.8 million or 60.3% to $326.3 million from $203.5 million for the same period in 2001, primarily due to commencement of commercial operation of the Casecnan Project in December 2001.

HomeServices operating revenue for the year ended December 31, 2002 increased $496.4 million or 77.3% to $1,138.3 million from $641.9 million for the same period in 2001, primarily due to current year acquisitions' contributions of $431.5 million. The remainder of HomeServices' increase was due to growth of existing companies of $105.3 million partially offset by a decrease of $40.4 million from a joint venture that was consolidated in 2001 and is accounted for under the equity method in 2002.

Income on equity investments for the year ended December 31, 2002 increased $0.9 million or 2.3% to $40.5 million from $39.6 million for the same period in 2001. The increase was primarily due to $8.8 million income from a HomeServices' joint venture which was fully consolidated in 2001 partially offset by $7.9 million lower earnings at CE Gen as a result of higher earnings from higher energy prices in 2001.

Interest and dividend income for the year ended December 31, 2002 increased $31.7 million or 128.9% to $56.3 million from $24.6 million for the same period in 2001. The increase was primarily due to increased interest income at CE Electric UK of $15.1 million due to the increased cash balance following the Yorkshire acquisition and increased corporate interest and dividends of $13.4 million primarily due to dividends received on the investment in Williams preferred securities.

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Other income for the year ended December 31, 2002 decreased $134.7 million or 63.5% to $77.4 million from $212.1 million for the same period in 2001. Other income in 2002 resulted primarily from the non-recurring gain on the sale of CE Gas of $54.3 million and equity AFUDC at Kern River of $10.6 million. These items were offset, in 2002, by losses from the write-down of investments at MidAmerican Energy of $21.9 million. Other income in 2001 resulted from the non-recurring gains from the sales of Northern Electric's supply business, Telephone Flat and Western States Geothermal of $196.7 million, $20.7 million and $9.8 million, respectively, and $10.4 million from the transfer of Bali shares. These items were partially offset, in 2001, by a charge related to the impairment of MEHC's interest in TPL of $58.8 million.

Cost of sales for the year ended December 31, 2002 decreased $497.2 million or 21.2% to $1,844.0 million from $2,341.2 million for the same period in 2001.

CE Electric UK cost of sales for the year ended December 31, 2002 decreased $713.2 million or 84.6% to $129.5 million from $842.7 million for the same period in 2001. The decrease was primarily due to the sale of the supply business in 2001.

MidAmerican Energy cost of sales for the year ended December 31, 2002 decreased $132.4 million or 11.8% to $988.9 million from $1,121.3 million for the same period in 2001, primarily due to decreases in regulated and non-regulated gas costs, caused by lower volumes and prices, partially offset by an increase in regulated electric costs caused by higher volumes, partially offset by the restructuring of the Cooper contract.

Northern Natural Gas had cost of sales of $1.1 million since its acquisition on August 16, 2002.

HomeServices cost of sales for the year ended December 31, 2002 increased $371.9 million or 94.0% to $767.6 million from $395.7 million for the same period in 2001. The increase was primarily due to acquisitions during 2002 of $315.6 million, and higher commission expense resulting from increased sales at existing HomeServices divisions, partially offset by $9.0 million of cost of sales from a joint venture which had been consolidated in 2001 and is accounted for under the equity method in 2002.

Operating expenses for the year ended December 31, 2002 increased $168.8 million or 14.3% to $1,345.2 million from $1,176.4 million for the same period in 2001. The increase was primarily due to higher costs at HomeServices of $99.1 million as a result of acquisitions, operating expenses due to the acquisitions of Northern Natural Gas of $95.0 million and Kern River of $27.2 million and plant operating expenses at the Zinc project and Casecnan of $33.9 million, partially offset by lower costs at MidAmerican Energy of $57.5 million primarily due to the restructuring of the Cooper contract and lower energy efficiency expenses and lower costs at CE Electric UK of $28.5 million due to the sale of the supply business.

Depreciation and amortization for the year ended December 31, 2002 decreased $12.8 million or 2.4% to $525.9 million from $538.7 million for the same period in 2001. The decrease was primarily due to discontinuance of amortizing goodwill beginning January 1, 2002 of $96.4 million, partially offset by a full year of operations at CE Casecnan of $22.0 million, higher depreciation at MidAmerican Energy of $17.2 million primarily due to higher Iowa revenue sharing accruals and a change in the estimated useful lives of electric general plant, depreciation expense due to the acquisitions of Kern River of $17.2 million and Northern Natural Gas of $18.2 million and increased amortization at HomeServices of $9.5 million primarily due to the amortization of the gross margin of pending sales contracts related to acquisitions.

Interest expense, less amounts capitalized, for the year ended December 31, 2002 increased $197.1 million or 47.7% to $609.9 million from $412.8 million for the same period in 2001. The increase was primarily due to the increase of interest expense at CE Electric UK of $71.3 million predominantly due to the debt related to the Yorkshire acquisition, interest expense due to debt related to the acquisitions of Kern River and Northern Natural Gas of $33.0 million and $23.0 million, respectively and the discontinuance of capitalizing interest related to the Casecnan Project, the Cordova project and the Zinc Recovery Project, all partially offset by capitalized interest at Kern River of $14.0 million.

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Tax expense for the year ended December 31, 2002 decreased $150.5 million or 60.2% to $99.6 million from $250.1 million for the same period in 2001. The decrease is due primarily to the tax expense related to the sale of the Northern Electric supply business in September 2001, the release of the tax obligation of $35.7 million in connection with the execution of the TPL restructuring agreement at CE Electric UK in 2002, and the recognition of a tax benefit in connection with the sale of the CE Gas assets in 2002.

Minority interest and preferred dividends for the year ended December 31, 2002 increased $57.0 million or 53.5% to $163.5 million from $106.5 million for the same period in 2001. Minority interest and preferred dividends includes the dividends on company-obligated mandatorily redeemable preferred securities of subsidiary trusts. The increase in minority interest and preferred dividends is primarily due to the issuance of company-obligated mandatorily redeemable preferred securities of subsidiary trusts relating to the Kern River and Northern Natural Gas acquisitions.

Effective January 1, 2001, MEHC changed its accounting policy regarding major maintenance and repairs for non-regulated gas projects, non-regulated plant overhaul costs and geothermal well rework costs to the direct expense method from the former policy of monthly accruals based on long-term scheduled maintenance plans for the gas projects and deferral and amortization of plant overhaul costs and geothermal well rework costs over the estimated useful lives. The cumulative effect of the change in accounting principle for 2001 was $4.6 million, net of taxes.

Results of Operations for the Year Ended December 31, 2001 and the Periods March 14, 2000 through December 31, 2000, and January 1, 2000 through March 13, 2000

The following is a discussion of the historical results of MEHC for the year ended December 31, 2001 and the period March 14, 2000 through December 31, 2000, and of its predecessor (referred to as MEHC (Predecessor)) for the period January 1, 2000 through March 13, 2000. Results for MEHC include the impact of the Teton Transaction beginning March 14, 2000 which are predominately the minority interest costs on issuance of company-obligated mandatorily redeemable preferred securities of a subsidiary trust and the effects of purchase accounting, including goodwill amortization and fair value adjustments to the carrying value of assets and liabilities.

Operating revenue for the year ended December 31, 2001 decreased $277.7 million or 5.6% to $4,696.8 million from $4,974.5 million for the same period in 2000.

MidAmerican Energy operating revenue for the year ended December 31, 2001 increased $72.4 million or 3.1% to $2,388.7 million from $2,316.3 million for the same period in 2000. MidAmerican Energy electric retail sales increased for the year ended December 31, 2001 from the same period in 2000 due to the warmer temperatures during the cooling season and an increase in non-weather related sales. Electric sales for resale increased for the year ended December 31, 2001 from the same period in 2000 due to higher production at the Cooper and Neal power plants and favorable market conditions. Regulated and non-regulated gas supplied increased due principally to growth in the non-regulated markets for the year ended December 31, 2001 compared to the same period in 2000.

CE Electric UK operating revenue for the year ended December 31, 2001 decreased $553.9 million or 27.7% to $1,444.0 million from $1,997.9 million for the same period in 2000, primarily due to the sale of the supply business in 2001 and changes in foreign exchange rates. The decrease in electricity supplied for the year ended December 31, 2001 is due to the sale of the Northern Electric supply business in September 2001. The increase in electricity distributed for the year ended December 31, 2001 is due to the addition of Yorkshire and changes in demand in the distribution area. The decrease in gas supplied in 2001 from 2000 reflects the sale of the Northern Electric supply business.

The remaining increase primarily relates to the increase of revenue at HomeServices due to acquisitions and the inclusion of a joint venture which was previously accounted for as an equity investment and the commencement of operations of the Cordova Project in June 2001.

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Income on equity investments for the year ended December 31, 2001 decreased $3.9 million or 9.0% to $39.6 million from $43.5 million for the same period in 2000. The decrease was primarily due to a joint venture at HomeServices previously accounted for as an equity investment that was fully consolidated in 2001.

Interest and dividend income for the year ended December 31, 2001 decreased $8.8 million or 26.3% to $24.6 million from $33.4 million for the same period in 2000. The decrease was due primarily to decreased interest income at CE Casecnan as funds previously invested were used for capital expenditures.

Other income for the year ended December 31, 2001 increased $174.6 million to $212.1 million from $37.5 million for the same period in 2000. The increase was primarily due to non-recurring gains from the sales of Northern Electric's supply business, Telephone Flat and Western States Geothermal recorded in 2001, of $196.7 million, $20.7 million and $9.8 million, respectively, and $10.4 million from the transfer of Bali shares. These items were partially offset by a write down of the investment in TPL during 2001 of $58.8 million.

Cost of sales for the year ended December 31, 2001 decreased $428.0 million or 15.5% to $2,341.2 million from $2,769.2 million for the same period in 2000. The decrease relates primarily to decreased cost of sales at CE Electric UK due to the sale of the Northern Electric supply business, lower foreign exchange rate and lower electricity volumes and prices, partially offset by increased volumes and prices for both regulated and non-regulated gas at MidAmerican Energy, and acquisitions at HomeServices.

Operating expenses for the year ended December 31, 2001 increased $45.0 million or 4.0% to $1,176.4 million from $1,131.4 million for the same period in 2000. The increase was primarily due to higher costs at HomeServices due to acquisitions and the inclusion of a joint venture which was previously accounted for as an equity investment and higher costs at MidAmerican Energy due to costs related to Cooper, accounts receivable discounts and bad debts, partially offset by lower costs at CE Electric UK due to the sale of the supply business, lower pension costs and a lower exchange rate, partially offset by the addition of Yorkshire. In addition, MEHC recorded $7.6 million in the period from January 1, 2000 through March 13, 2000 which represents the costs incurred related to the Teton Transaction.

Depreciation and amortization for the year ended December 31, 2001 increased $58.1 million or 12.1% to $538.7 million from $480.6 million for the same period in 2000. This increase was due to higher depreciation at MidAmerican Energy due to inclusion of Iowa revenue sharing accrual and an increase in depreciation rates implemented in 2001 and amortization of the gross margin of pending sales contracts related to the HomeServices acquisitions, partially offset by lower depreciation at CE Electric UK due to lower amortization of operational assets and lower exchange rate, partially offset by the addition of Yorkshire.

Interest expense, less amounts capitalized, for the year ended December 31, 2001 increased $15.6 million or 3.9% to $412.8 million from $397.2 million for the same period in 2000. This increase is due to increased interest expense associated with the debt acquired with Yorkshire and lower capitalized interest on the mineral extraction process, partially offset by lower average outstanding debt balances and lower foreign exchange rates at CE Electric UK.

Tax expense for the year ended December 31, 2001 increased $165.8 million or 196.7% to $250.1 million from $84.3 million for the same period in 2000. The increase is due primarily to the tax on the gain related to the sale of Northern Electric supply business and higher pre-tax income.

Minority interest and preferred dividends for the year ended December 31, 2001 increased $13.0 million or 13.9% to $106.5 million from $93.5 million for the same period in 2000. The increase is primarily due to the issuance of company-obligated mandatorily redeemable preferred securities of subsidiary trusts relating to the Teton Transaction and increased minority interest at HomeServices related to certain mortgage and title joint ventures.

The cumulative effect of change in accounting principle of $4.6 million in 2001 represents the change in accounting for major maintenance and overhauls.

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Effects of Inflation

In recent years, inflation has been modest and has not had a material impact upon the results of our operations.

Liquidity and Capital Resources

MEHC has available a variety of sources of liquidity and capital resources, both internal and external. These resources provide funds required for current operations, construction expenditures, debt retirement and other capital requirements. MEHC may from time to time seek to retire its outstanding debt through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, MEHC's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

MEHC's cash and cash equivalents were $852.9 million at March 31, 2003, compared $844.4 million at December 31, 2002. Each of MEHC's direct or indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements at each subsidiary, the assets of each subsidiary may be pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should not be assumed that any asset of any subsidiary of MEHC will be available to satisfy the obligations of MEHC or any of its other subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof.

In addition, MEHC recorded separately, in restricted cash and short-term investments and deferred charges and other assets, restricted cash and investments of $81.2 million and $58.7 million at March 31, 2003, and December 31, 2002, respectively. The restricted cash balance for both periods is comprised primarily of amounts deposited in restricted accounts which are reserved for the service of debt obligations.

Cash flows from operating activities for the three-month period ended March 31, 2003 increased $203.2 million to $385.8 million from $182.6 million for the same period in 2002. The increase was primarily due to timing of changes in working capital and the positive impacts of the Kern River, Northern Natural Gas and HomeServices acquisitions.

MEHC generated cash flows from operations of $757.7 million for the year ended December 31, 2002, compared with $847.0 million for the same period in 2001. The decrease was primarily due to timing of changes in working capital activities, partially offset by positive impacts of the Kern River, Northern Natural Gas and real estate companies acquisitions.

The remaining decrease to cash and cash equivalents is primarily due to construction and development costs, capital expenditures related to operating projects and repayments of debt and other obligations offset by the issuance of subsidiary and project debt.

Kern River's 2003 Expansion Project

Kern River has completed the construction of its 2003 Expansion Project at a total cost of approximately $1.2 billion. The expansion, which was placed into operation on May 1, 2003, increased the design capacity of the existing Kern River pipeline by 885,626 Dth per day to 1,755,626 Dth per day.

Kern River Funding Corporation, a wholly owned subsidiary of Kern River, issued $836 million of its 4.893% Senior Notes with a final maturity on April 30, 2018. The proceeds were used to repay all of the approximately $815 million of outstanding borrowings under Kern River's $875 million credit facility. Kern River entered into this credit facility in 2002 to finance the construction of the 2003 Expansion Project. The credit facility was canceled and a completion guarantee issued by MEHC in favor of the lenders as part of the credit facility terminated upon completion of the 2003 Expansion Project on May 1, 2003.

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MidAmerican Energy Operating Projects and Construction and Development Costs

MidAmerican Energy's primary need for capital is utility construction expenditures. For the first three months of 2003, utility construction expenditures at MidAmerican Energy totaled $76.6 million, including allowance for funds used during construction, or capitalized financing costs, and Quad Cities Station nuclear fuel purchases.

Forecasted utility construction expenditures, including allowance for funds used during construction, are $368 million for 2003. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews.

Through 2007, MidAmerican Energy plans to develop and construct three electric generating projects in Iowa. The projects would provide service to regulated retail electricity customers and, subject to regulatory approvals, be included in regulated rate base in Iowa, Illinois and South Dakota. Wholesale sales may also be made from the plants to the extent the power is not needed for regulated retail service. MidAmerican Energy expects to invest approximately $1.44 billion in the three projects.

The first project is a natural gas-fired combined cycle unit with an estimated cost of $357 million, plus allowance for funds used during construction. MidAmerican Energy will own 100% of the plant and operate it. MidAmerican Energy has received a certificate from the IUB allowing it to construct the plant. Also, on May 29, 2002, the IUB issued an order that provides the ratemaking principles for the plant. The plant will be operated in simple cycle mode during 2003 and 2004, resulting in 327 MW of accredited capacity. Commercial operation of the simple cycle mode began on May 5, 2003. The combined cycle operation is expected to commence in 2005, resulting in an expected additional 190 MW of accredited capacity.

The second project is currently under development and is expected to be a 790-MW (based on expected accreditation) super-critical-temperature, coal-fired plant fueled with low-sulfur coal. If constructed, MidAmerican Energy will operate the plant and expects to own approximately 475 MW of the plant. MidAmerican Energy expects to invest approximately $759 million in the project, plus allowance for funds used during construction. Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large base-load plants in Iowa. On January 23, 2003, MidAmerican Energy received an order approving the issuance of a certificate from the IUB allowing it to construct the plant. MidAmerican Energy also made a filing with the IUB for approval of ratemaking principles pertaining to this plant. On March 20, 2003, MidAmerican Energy entered into a settlement agreement, with the Iowa Office of Consumer Advocate, related to the ratemaking principles application which agreement was subsequently filed with the IUB. On May 29, 2003, the IUB issued its order approving the ratemaking principles for this plant. On February 12, 2003, MidAmerican Energy executed a contract with Mitsui & Co. Energy Development, Inc. for the engineering, procurement and construction of the plant and issued a limited notice to proceed authorizing detailed engineering. A full notice to proceed authorizing construction is expected following the receipt of environmental and other required permits. Continued development of this project is subject to receiving orders from the IUB approving construction of the associated transmission facilities.

The third project is currently under development and is expected to be wind power facilities totaling 310 MW based on the nameplate rating. Generally speaking, accredited capacity ratings for wind power facilities will likely fall within 15% to 20% of the nameplate ratings. If constructed, MidAmerican Energy will own and operate these facilities, which are expected to cost approximately $323 million, plus associated transmission facilities. MidAmerican Energy's plan to construct the wind project is in conjunction with a settlement proposal to extend through December 31, 2010, an electric rate freeze that is currently scheduled to expire at the end of 2005. The proposed settlement was filed with the IUB along with the related ratemaking principles application and is subject to approval by the IUB.

Casecnan Construction Contract

The Casecnan Project was initially constructed pursuant to a fixed-price, date-certain, turnkey construction contract, or the Hanbo Contract, on a joint and several basis by Hanbo Corporation, or

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Hanbo, and Hanbo Engineering and Construction Co., Ltd., or HECC, both of which are South Korean corporations. On May 7, 1997, CE Casecnan terminated the Hanbo Contract due to defaults by Hanbo and HECC including the insolvency of both companies. On the same date, CE Casecnan entered into a new fixed-price, date certain, turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project, or the Replacement Contract. The work under the Replacement Contract was conducted by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa., (collectively, the Contractor), working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd.

On November 20, 1999, the Replacement Contract was amended to extend the Guaranteed Substantial Completion Date for the Casecnan Project to March 31, 2001. This amendment was approved by the lenders' independent engineer under the Trust Indenture.

On February 12, 2001, the Contractor filed a Request for Arbitration with the ICC seeking schedule relief of up to 153 days through August 31, 2001 resulting from various alleged force majeure events. In its March 20, 2001 Supplement to Request for Arbitration, the Contractor also seeks compensation for alleged additional costs of approximately $4 million it incurred from the claimed force majeure events to the extent it is unable to recover from its insurer. On April 20, 2001, the Contractor filed a further supplement seeking an additional compensation for damages of approximately $62 million for the alleged force majeure event (and geologic conditions) related to the collapse of the surge shaft. The Contractor has alleged that the circumstances surrounding the placing of the Casecnan Project into commercial operation in December 2001 amounted to a repudiation of the Replacement Contract and has filed a claim for unspecified quantum meruit damages, and has further alleged that the delay liquidated damages clause which provides for payments of $125,000 per day for each day of delay in completion of the Casecnan Project for which the Contractor is responsible is unenforceable. The arbitration is being conducted applying New York law and pursuant to the rules of the ICC.

Hearings have been held in connection with this arbitration in July 2001, September 2001, January 2002, March 2002, November 2002 and January 2003. As part of those hearings, on June 25, 2001, the arbitration tribunal temporarily enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di Roma in support of the Contractor's obligations to CE Casecnan for delay liquidated damages. As a result of the continuing nature of that injunction, on April 26, 2002, CE Casecnan and the Contractor mutually agreed that no demands would be made on the Banca di Roma demand guaranty except pursuant to an arbitration award. As of March 31, 2003, however, CE Casecnan has received approximately $6.0 million of liquidated damages from demands made on the demand guarantees posted by Commerzbank on behalf of the Contractor. On November 7, 2002, the ICC issued the arbitration tribunal's partial award with respect to the Contractor's force majeure and geologic conditions claims. The arbitration panel awarded the Contractor 18 days of schedule relief in the aggregate for all of the force majeure events and awarded the Contractor $3.8 million with respect to the cost of the collapsed surge shaft. The $3.8 million is shown as part of the accounts payable and accrued expenses balance at March 31, 2003 and December 31, 2002. All of the Contractor's other claims with respect to force majeure and geologic conditions were denied.

Further hearings on the Contractor's repudiation and quantum meruit claims, the alleged unenforceability of the delay liquidated damages clause and certain other matters had been scheduled for March 24 through March 28, 2003, but were postponed as a result of the commencement of military action in Iraq. The hearings have been rescheduled for June 30 through July 11, 2003.

If the Contractor were to prevail on its claim that the delay liquidated damages clause is unenforceable, CE Casecnan would not be entitled to collect such delay damages for the period from March 31, 2001 through December 11, 2001. If the Contractor were to prevail in its repudiation claim and prove quantum meruit damages in excess of amounts paid to the Contractor, CE Casecnan could be liable to make additional payments to the Contractor. CE Casecnan believes all of such allegations and claims are without merit and is vigorously contesting the Contractor's claims.

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Casecnan NIA Arbitration

Under the terms of the Project Agreement, NIA has the option of timely reimbursing CE Casecnan directly for certain taxes CE Casecnan has paid. If NIA does not so reimburse CE Casecnan, the taxes paid by CE Casecnan result in an increase in the water delivery fee. The payment of certain other taxes by CE Casecnan results automatically in an increase in the water delivery fee. As of March 31, 2003, CE Casecnan has paid approximately $58.1 million in taxes, which as a result of the foregoing provisions results in an increase in the water delivery fee. NIA has failed to pay the portion of the water delivery fee each month, related to the payment of these taxes by CE Casecnan. As a result of this non-payment, on August 19, 2002, CE Casecnan filed a Request for Arbitration against NIA, seeking payment of such portion of the water delivery fee and enforcement of the relevant provision of the Project Agreement going forward. The arbitration will be conducted in accordance with the rules of the ICC.

NIA filed its Answer and Counterclaim on March 31, 2003. In its Answer, NIA asserts, among other things, that most of the taxes which CE Casecnan has factored into the water delivery fee compensation formula do not fall within the scope of the relevant section of the Project Agreement, that the compensation mechanism itself is invalid and unenforceable under Philippine law and that the Project Agreement is inconsistent with the Philippine build-operate-transfer, or BOT, law. As such, NIA seeks dismissal of CE Casecnan's claims and a declaration from the arbitral tribunal that the taxes which have been taken into account in the water delivery fee compensation mechanism are not recoverable thereunder and that, at most, certain taxes may be directly reimbursed (rather than compensated for through the water delivery fee) by NIA. NIA also counterclaims for approximately $7 million which it alleges is due to it as a result of the delayed completion of the Casecnan Project. On April 23, 2003, NIA filed a Supplemental Counterclaim in which it asserts that the Project Agreement is contrary to Philippine law and public policy and by way of relief seeks a declaration that the Project Agreement is void from the beginning or should be cancelled, or alternatively, an order for reformation of the Project Agreement or any portions or sections thereof which may be determined to be contrary to such law and or public policy. On May 23, 2003, CE Casecnan filed its reply to NIA's counterclaims. CE Casecnan intends to vigorously contest all of NIA's assertions and counterclaims.

The three member arbitration panel has been confirmed by the ICC and an initial organizational hearing was held on April 28, 2003. Hearings on this matter are scheduled for July 2004.

Included in revenue, for the three months ended March 31, 2003 and 2002, were $5.5 million and $5.8 million, respectively, of tax compensation for water delivery fees under the Project Agreement, none of which has been paid. As of March 31, 2003 and December 31, 2002, the net receivable for the tax compensation piece of the water delivery fees invoiced since the start of commercial operations totaled $29.8 million and $24.3 million, respectively.

Casecnan Stockholder Litigation

Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro forma financial projections of the Casecnan Project prepared following commencement of commercial operations, in February 2002, MEHC, through its indirect wholly owned subsidiary CE Casecnan Ltd., advised the minority stockholder LaPrairie Group Contractors (International) Ltd., or LPG, that MEHC's indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against, inter alia, CE Casecnan Ltd. and MEHC. In the complaint, LPG seeks compensatory and punitive damages for alleged breaches of the stockholder agreement and alleged breaches of fiduciary duties allegedly owed by CE Casecnan Ltd. and MEHC to LPG. The complaint also seeks injunctive relief against all defendants and a declaratory judgment that LPG is entitled to maintain its 15% interest in CE Casecnan. The impact, if any, of this litigation on CE Casecnan cannot be determined at this time.

In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc., or San Lorenzo, an original shareholder substantially all of whose shares in CE Casecnan MEHC purchased in 1998,

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threatened to initiate legal action in the Philippines in connection with certain aspects of its option to repurchase such shares on or prior to commercial operation of the Casecnan Project. CE Casecnan believes that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, will vigorously defend any such action.

Philippine Political Risks

In connection with an interagency review of approximately 40 independent power project contracts in the Philippines, the Casecnan Project (together with four other unrelated projects) has reportedly been identified as raising legal and financial questions and, with those projects, has been prioritized for renegotiation. MEHC's subsidiaries' Upper Mahiao, Malitbog, and Mahanagdong projects have also reportedly been identified as raising financial questions. No written report has yet been issued with respect to the interagency review, and the timing and nature of steps, if any that the Philippine Government may take in this regard are not known. Accordingly, it is not known what, if any, impact the government's review will have on the operations of MEHC's Philippine Projects. CE Casecnan representatives, together with certain current and former government officials, also have been requested to appear, and have appeared during 2002 and 2003, before a Philippine Senate committee which has raised questions and made allegations with respect to the Casecnan Project's tariff structure and implementation.

On May 5, 2003, the Philippine Supreme Court issued its ruling in a case involving an unsolicited BOT project for the development, construction and operation of the new Manila International Airport. Various members of Congress and labor unions initiated the action in the Philippine Supreme Court on September 17, 2002 seeking to enjoin the enforcement of the BOT agreement with an international consortium known as PIATCO, or the PIATCO Agreement. The PIATCO Consortium is unrelated to CE Casecnan or MEHC. On March 4, 2003, PIATCO separately initiated an ICC arbitration pursuant to the terms of the PIATCO Agreement. The Supreme Court, in its ruling, stated that there were no unresolved factual issues and therefore it had original jurisdiction and concluded that the pendency of the arbitration did not preclude the court from ruling on a case brought by non-parties to the PIATCO Agreement, such as members of the Philippine Congress or non-governmental organizations. In a public speech on November 29, 2002 prior to the December 10, 2002 oral arguments before the Philippine Supreme Court, Philippine President Arroyo stated that she would not honor the PIATCO Agreement because the executive branch's legal department had concluded it was "null and void". In light of that announcement, the project owners stopped work on the project, which is approximately 90% complete and accordingly has not been placed into commercial operation. In its 10 to 3 ruling (with one abstention) issued on May 5, 2003, the Philippine Supreme Court ruled that the PIATCO Agreement was contrary to Philippine law and public policy and was "null and void". CE Casecnan is assessing the impact of the PIATCO ruling on the Casecnan Project.

On April 24, 2003, S&P lowered its rating of CE Casecnan to 'BB' from 'BB+' as a result of S&P's downgrade of the Republic of the Philippines, or ROP. The downgrade of the ROP by S&P reflected the country's growing debt burden and fiscal rigidity.

On May 8, 2003, Moody's placed the Ba2 senior secured notes rating of CE Casecnan on review for possible downgrade, noting NIA's supplemental counterclaim seeking to have the Project Agreement declared void. Moody's noted that actions by government related agencies and the resulting instability of contractual arrangements was becoming inconsistent with their rating approach that attaches significant benefit to offtake arrangements with those government supported entities.

Other Debt Issuances and Redemptions

On January 14, 2003, MidAmerican Energy issued $275.0 million of 5.125% medium-term notes due in 2013. The proceeds were used to refinance existing debt and for other corporate purposes.

On April 23, 2003, Yorkshire Power Group Limited, a wholly owned subsidiary of MEHC, reported that it had authorized the redemption in full of the outstanding shares of the Yorkshire Capital Trust I, 8.08% Trust Securities, due June 30, 2038. The Trust Securities will be redeemed on June 9, 2003, at a redemption price of 100% of the principal amount ($25 liquidation amount per each

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Trust Security) plus accrued distributions of $0.381555555 per Trust Security to the redemption date. The redemption price will be paid to holders of the Trust Security on the redemption date. At March 31, 2003 and December 31, 2002, $250.5 million and $249.7 million, respectively, of the Trust Securities are included in subsidiary and project debt.

Williams Preferred Stock

On June 10, 2003, Williams repurchased, for approximately $289 million, all of the shares of their 9-7/8% Cumulative Convertible Preferred Stock originally acquired by MEHC in March 2002 for $275 million.

Obligations and Commitments

MEHC has contractual obligations and commercial commitments that may affect its financial condition. Contractual obligations to make future payments arise from parent company and subsidiary long-term debt and notes payable, preferred equity securities, operating leases and power and fuel purchase contracts. Other obligations arise from unused lines of credit and letters of credit. Material obligations as of December 31, 2002 are as follows (in thousands):


  Payments Due by Period
  Total Less Than 1
Year		 2-3 Years 4-5 Years After 5
Years
Contractual Cash Obligations:
Parent company long-term debt(1) $ 2,539.5   $ 215.0   $ 260.0   $ 550.0   $ 1,514.5  
Subsidiary and project debt(1)   7,332.3     255.2     847.2     587.2     5,642.7  
Company-obligated mandatorily redeemable                              
Preferred securities of subsidiary trusts   2,063.4     150.0     288.5     468.0     1,156.9  
Mandatorily redeemable preferred securities of subsidiaries   93.3     93.3     —     —     —  
Coal, electricity and natural gas contract commitments(2)   493.1     168.5     229.5     32.9     62.2  
Operating leases(2)   293.2     60.8     85.4     60.3     86.7  
Total contractual cash obligations $ 12,814.8   $ 942.8   $ 1,710.6   $ 1,698.4   $ 8,463.0  

  Commitment Expiration per Period
  Total Less Than 1
Year		 2-3 Years 4-5 Years After 5
Years
Other Commercial Commitments:
Unused parent company revolving lines
of credit		 $ 352.3   $ 352.3   $ —   $ —   $ —  
Parent company letters of credit   47.7     —     47.7     —     —  
Unused subsidiaries lines of credit   350.0     249.7     100.3     —     —  
Parent company guarantee of subsidiary debt   174.8     1.4     3.6     2.9     166.9  
Subsidiary lines of credit from parent company   10.0     —     —     —     10.0  
Total other commercial commitments $ 934.8   $ 603.4   $ 151.6   $ 2.9   $ 176.9  
(1) Excludes certain unamortized debt premiums and discounts.
(2) The fuel and energy commitments and operating leases are not reflected on the consolidated balance sheets.

As of March 31, 2003 (but not included in the table above), Northern Natural Gas had $59.3 million of obligations to deliver 12.2 Bcf of natural gas in 2003. The obligations are revalued based on market prices for natural gas, with changes in value included in the statement of operations. In 2002, Northern Natural Gas entered into natural gas commodity price swaps and index basis swaps to effectively fix the deferred obligation balance. These swaps have a net receivable balance of

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$10.8 million at March 31, 2003. The swaps are revalued based on market prices for natural gas, with changes in value included in the statement of operations. Therefore, any further changes in the market value of the deferred obligations are expected to be offset by a corresponding change in the opposite direction in the market value of the swaps. However, at March 31, 2003, Northern Natural Gas had a $17.8 million receivable position with a third party energy marketer relating to these swaps. Since the date of entering into these swaps, there have been public announcements that this third party's financial condition has deteriorated as a result of, among other factors, reduced liquidity. This receivable would increase by approximately $12.2 million if the price curve of natural gas were to increase by $1/MMBtu from levels at March 31, 2003. MEHC has not recorded an allowance on this receivable as of March 31, 2003, and is monitoring the situation.

As of December 31, 2002 (but not included in the table above), Northern Natural Gas had $52.0 million of obligations to deliver 12.2 Bcf of natural gas in 2003. The obligations are revalued based on market prices for natural gas, with changes in value included in the statement of operations. In 2002, Northern Natural Gas entered into natural gas commodity price swaps and index basis swaps to effectively fix the deferred obligation balance. These swaps had a net receivable balance of $3.4 million at December 31, 2002. The swaps are revalued based on market prices for natural gas, with changes in value included in the statement of operations. Therefore, any further changes in the market value of the deferred obligations are expected to be offset by a corresponding change in the opposite direction in the market value of the swaps. However, at December 31, 2002, Northern Natural Gas had a $10.4 million receivable position with a third party energy marketer relating to these swaps. Since the date of entering into these swaps, there have been public announcements that this third party's financial condition has deteriorated as a result of, among other factors, reduced liquidity. This receivable would increase by approximately $12.2 million if the price curve of natural gas were to increase by $1/MMBtu from levels at December 31, 2002. MEHC has not recorded an allowance on this receivable as of December 31, 2002, and is monitoring the situation.

There have been no material changes in the contractual obligations and commercial commitments from the information provided in the table above other than the issuance of $836 million of Kern River Funding Corporation's 4.893% Senior Notes, $275 million of MidAmerican Energy's 5.125% medium-term notes as discussed in this section and $450 million of MEHC's 3.50% Senior Notes offered in this prospectus.

On May 23, 2003, MEHC terminated a $150 million credit facility, and reduced an additional $250 million credit facility to $100 million. The remaining $100 million facility expires June 23, 2003. MEHC expects to enter into a new credit facility prior to or on June 23, 2003.

Off-Balance Sheet Arrangements

MEHC has certain investments that are accounted for under the equity method in accordance with generally accepted accounting principles, or GAAP. Accordingly, an amount is recorded on MEHC's balance sheet as an equity investment and is increased or decreased for MEHC's pro-rata share of earnings or losses, respectively, less any dividend distribution from such investments.

At March 31, 2003 and December 31, 2002, MEHC's consolidated subsidiaries' and joint ventures' total outstanding indebtedness was approximately $7.4 billion, which does not include $432 million and $436 million, representing MEHC's share of outstanding indebtedness of CE Gen at March 31, 2003 and December 31, 2002, respectively. In addition, as of March 31, 2003 and December 31, 2002, MEHC's investments, which are accounted for under the equity method, had an aggregate of $43.7 million in outstanding letters of credit. MEHC's pro-rata share of the outstanding letters of credit was $21.9 million as of March 31, 2003 and December 31, 2002.

New Accounting Pronouncements and Reporting Issues

Effective January 1, 2003 MEHC adopted Statement of Financial Accounting Standards, or SFAS, No. 143, "Accounting for Asset Retirement Obligations," or SFAS 143. This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. The cumulative effect of initially applying this statement was immaterial.

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MEHC's review of its regulated entities identified legal retirement obligations for nuclear decommissioning, wet and dry ash landfills and offshore and minor lateral pipeline facilities. On January 1, 2003, MEHC recorded $289.3 million of asset retirement obligation, or ARO, liabilities; $13.9 million of ARO assets, net of accumulated depreciation; $114.6 million of regulatory assets; and reclassified $1.0 million of accumulated depreciation to the ARO liability. The initial ARO liability recognized includes $266.5 million that pertains to obligations associated with the decommissioning of the Quad Cities nuclear station. The $266.5 million includes a $159.8 million nuclear decommissioning liability that had been recorded at December 31, 2002. The adoption of this statement did not have a material impact on the operations of the regulated entities, as the effects were offset by the establishment of regulatory assets, totaling $114.6 million, pursuant to SFAS No. 71.

During the three-month period ended March 31, 2003, MEHC recorded, as a regulatory asset, accretion related to the ARO liability of $4.2 million resulting in an ARO liability balance of $293.5 million at March 31, 2003.

In April 2003, the Financial Accounting Standards Board, or FASB, issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," or SFAS 149. SFAS 149 amends SFAS No. 133 for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. SFAS 149 also amends certain other existing pronouncements. It will require contracts with comparable characteristics to be accounted for similarly. In particular, SFAS 149 clarifies when a contract with an initial net investment meets the characteristic of a derivative and clarifies when a derivative that contains a financing component will require special reporting in the statement of cash flows. SFAS 149 is effective for MEHC for contracts entered into or modified after June 30, 2003. MEHC and its subsidiaries are evaluating the impact of adopting the requirements of SFAS 149.

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity," or SFAS 150. SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments ith characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). SFAS 150 is effective for MEHC for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the third quarter of 2003. MEHC expects the adoption of SFAS 150 to result in the reclassification of approximately $2.1 billion to liabilities with a corresponding reduction in their current presentation between the liabilities section and the equity section. There will also be a reclassification of income statement amounts which will have no net income or cash flow impact.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

MEHC is exposed to market risk, including changes in the market price of certain commodities and interest rates. To manage the price volatility relating to these exposures, MEHC enters into various financial derivative instruments. Senior management provides the overall direction, structure, conduct and control of MEHC's risk management activities, including the use of financial derivative instruments, authorization and communication of risk management policies and procedures, strategic hedging program guidelines, appropriate market and credit risk limits, and appropriate systems for recording, monitoring and reporting the results of transactional and risk management activities.

At December 31, 2002, MEHC had fixed-rate long-term debt, company-obligated mandatorily redeemable preferred securities of subsidiary trusts, and subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts of $11,683.2 million in principal amount and having a fair value of $12,188.8 million. These instruments are fixed-rate and therefore do not expose MEHC to the risk of earnings loss due to changes in market interest rates. However, the fair value of these instruments would decrease by approximately $397.1 million if interest rates were to increase by 10% from their levels at December 31, 2002. In general, such a decrease in fair value would impact earnings and cash flows only if MEHC were to reacquire all or a portion of these instruments prior to their maturity.

At December 31, 2002, MEHC had floating-rate obligations of $425.1 million that expose MEHC to the risk of increased interest expense in the event of increases in short-term interest rates. These obligations are not hedged. If the floating rates were to increase by 1% MEHC's consolidated interest expense for unhedged floating-rate obligations would increase by approximately $0.4 million each month in which such increase continued based upon December 31, 2002 principal balances.

MEHC's exposure to market risk has not materially changed since December 31, 2002.

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BUSINESS

General

We are a United States-based privately owned global energy company. Our subsidiaries' principal businesses are regulated electric and natural gas utilities, regulated interstate natural gas transmission and electric power generation. Our operations are organized and managed on seven distinct platforms: MidAmerican Energy Company, or MidAmerican Energy, Kern River Gas Transmission Company, or Kern River, Northern Natural Gas Company, or Northern Natural Gas, CE Electric UK Funding, or CE Electric UK (which includes Northern Electric plc, or Northern Electric, and Yorkshire Power Group Ltd., or Yorkshire), CalEnergy Generation – Domestic, CalEnergy Generation – Foreign (the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively the Leyte Projects) and the Casecnan Project) and HomeServices of America, Inc., or HomeServices. Through six of these platforms, we own and operate a combined electric and natural gas utility company in the United States, two natural gas pipeline companies in the United States, two electricity distribution companies in the United Kingdom, and a diversified portfolio of domestic and international independent power projects. We also own the second largest residential real estate brokerage firm in the United States.

Our principal subsidiaries generate, transmit, store, distribute and supply energy. Our electric and natural gas utility subsidiaries currently serve approximately 4.3 million electricity customers and approximately 660,000 natural gas customers. Our natural gas pipeline subsidiaries operate interstate natural gas transmission systems with approximately 18,300 miles of pipeline in operation and peak delivery capacity of 6.2 Bcf of natural gas per day. We have interests in 6,191 net owned MW of power generation facilities in operation and construction, including 4,618 net owned MW in facilities that are part of the regulated return asset base of its electric utility business (as further described in "Business — MidAmerican Energy — Electric Operations") and 1,573 net owned MW in non-utility power generation facilities. Substantially all of the non-utility power generation facilities have long-term contracts for the sale of energy and/or capacity from the facilities.

On March 14, 2000, we and an investor group comprised of Berkshire Hathaway, Walter Scott, Jr., one of our Directors, David L. Sokol, our Chairman and Chief Executive Officer, and Gregory E. Abel, our President and Chief Operating Officer, closed on a definitive agreement and plan of merger whereby the investor group acquired all of our outstanding common stock in a transaction referred to in this prospectus as the Teton Transaction. As a result of the Teton Transaction, Berkshire Hathaway owns approximately 9.7% of our voting stock, Mr. Scott owns approximately 86% of our voting stock, Mr. Sokol owns approximately 3% of our voting stock and Mr. Abel owns approximately 1% of our voting stock.

Our principal executive offices are located at 666 Grand Avenue, Des Moines, Iowa 50309 and our telephone number is (515) 242-4300. We initially incorporated in 1971 under the laws of the State of Delaware and were reincorporated in 1999 in Iowa, at which time we changed our name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.

MidAmerican Energy

MidAmerican Energy is the largest energy company headquartered in Iowa, with $4.1 billion of assets as of March 31, 2003, and revenue for 2002 totaling $2.2 billion. MidAmerican Energy is principally engaged in the business of generating, transmitting, distributing and selling electric energy and in distributing, selling and transporting natural gas. MidAmerican Energy distributes electricity at retail in Council Bluffs, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities (Davenport and Bettendorf, Iowa and Rock Island, Moline and East Moline, Illinois); and a number of adjacent communities and areas. It also distributes natural gas at retail in Cedar Rapids, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities; Sioux Falls, South Dakota; and a number of adjacent communities and areas. As of December 31, 2002, MidAmerican Energy had approximately 681,000 retail electric customers and 660,000 retail natural gas customers.

In addition to retail sales, MidAmerican Energy sells electric energy and natural gas to other utilities, marketers and municipalities outside of MidAmerican Energy's delivery system. These sales

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are referred to as wholesale sales. It also transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas.

MidAmerican Energy's regulated electric and gas operations are conducted under franchises, certificates, permits and licenses obtained from state and local authorities. The franchises, with various expiration dates, are typically for 25-year terms.

MidAmerican Energy has a diverse customer base consisting of residential, agricultural and a variety of commercial and industrial customer groups. Among the primary industries served by MidAmerican Energy are those that are concerned with food products, the manufacturing, processing and fabrication of primary metals, real estate, farm and other non-electrical machinery, and cement and gypsum products.

For the three months ended March 31, 2003, MidAmerican Energy derived approximately 39% of its gross operating revenues from its electric utility business, 51% from its gas utility business and 10% from its non-regulated business activities. For the year ended December 31, 2002, MidAmerican Energy derived approximately 61% of its gross operating revenues from its electric utility business, 31% from its gas utility business and 8% from its non-regulated business activities. For 2001 and 2000, the corresponding percentages were 56% electric, 37% gas and 7% non-regulated and 53% electric, 41% gas and 6% non-regulated, respectively. The change in revenue mix is principally driven by changes in natural gas prices.

There are seasonal variations in MidAmerican Energy's electric and gas businesses, which are principally related to the use of energy for air conditioning and heating. In 2002, 41% of MidAmerican Energy's electric utility revenues were reported in the months of June, July, August and September, and 47% of MidAmerican Energy's gas utility revenues were reported in the months of January, February, March and December.

Electric Operations

The electric utility industry continues to undergo regulatory change. Traditionally, prices charged by electric utility companies have been regulated by federal and state commissions and have been based on cost of service. In recent years, changes have been occurring that move the electric utility industry toward a more competitive, market-based pricing environment. These changes may have a significant impact on the way MidAmerican Energy does business.

MidAmerican Energy manages its operations as four separate business units: generation, energy delivery, transmission, and marketing and sales. The generation segment derives most of its revenue from the sale of regulated wholesale electricity and non-regulated wholesale and retail natural gas. The energy delivery segment derives its revenue principally from the delivery of regulated electricity and natural gas, while the transmission segment obtains most of its revenue from the sale of transmission capacity. The marketing and sales segment receives its revenue principally from non-regulated sales of natural gas and electricity.

For the year ended December 31, 2002, regulated electric sales by MidAmerican Energy by customer class were as follows: 19.8% were to residential customers, 14.2% were to small general service customers, 24.5% were to large general service customers, 9.1% were to other customers, and 32.4% were wholesale sales. For the year ended December 31, 2002, regulated electric sales by MidAmerican Energy by jurisdiction were as follows: 88.5% to Iowa, 10.7% to Illinois and 0.8% to South Dakota.

The annual hourly peak demand on MidAmerican Energy's electric system occurs principally as a result of air conditioning use during the cooling season. In July 2002, MidAmerican Energy recorded an hourly peak demand of 3,889 MW, which was 56 MW greater than MidAmerican Energy's previous record hourly peak of 3,833 MW set in 1999.

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The following table sets out certain information concerning MidAmerican Energy's power generation facilities based upon summer 2002 accreditation:


Operating Project (1) Facility Net
Capacity (MW)(2)		 Net MW
Owned(2)		 Fuel Location Commercial
Operation
                   
Coal Facilities:                  
Council Bluffs Energy Center Units 1 & 2   133     133   Coal Iowa 1954, 1958
Council Bluffs Energy Center Unit 3   690     546   Coal Iowa 1978
Louisa Generation Station   700     616   Coal Iowa 1983
Neal Generation Station Units 1 & 2   435     435   Coal Iowa 1964, 1972
Neal Generation Station Unit 3   515     371   Coal Iowa 1975
Neal Generation Station Unit 4   644     261   Coal Iowa 1979
Ottumwa Generation Station   708     368   Coal Iowa 1981
Riverside Generation Station   135     135   Coal Iowa 1925-61
Total coal facilities   3,960     2,865  
Other Facilities:
Combustion Turbines   785     785   Gas/Oil Iowa 1969-95
Moline Water Power   3     3   Hydro Illinois 1970
Quad Cities Generating Station   1,636     409   Nuclear Illinois 1974
Portable Power Modules   56     56   Oil Iowa 2000
Total other facilities   2,480     1,253  
Accredited generating capacity   6,440     4,118  
Projects Under Construction —
Greater Des Moines Energy Center		   500     500   Gas Iowa 2003-05
Total Power Generation Capacity   6,940     4,618        
(1) MidAmerican Energy operates all such power generation facilities other than Quad Cities Generating Station and Ottumwa Generation Station.
(2) Represents accredited net generating capability. Actual MW may vary depending on operating conditions and plant design for operating projects. Net MW owned indicates ownership of accredited capacity for the summer of 2002 as approved by the Mid-Continent Area Power Pool, or MAPP.

MidAmerican Energy's accredited net generating capability in the summer of 2002 was 4,724 MW. Accredited net generating capability represents the amount of generation available to meet the requirements on MidAmerican Energy's system and consists of MidAmerican Energy-owned generation of 4,118 MW, generation under power purchase contracts of 630 MW and the net amount of capacity purchases and sales of (24) MW. The net generating capability at any time may be less than it would otherwise be due to regulatory restrictions, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling or modifications.

Through 2007, MidAmerican Energy plans to develop and construct three electric generating projects in Iowa. The projects would provide service to regulated retail electricity customers and, subject to regulatory approvals, be included in its regulated rate base in Iowa, Illinois and South Dakota. Wholesale sales may also be made from the plants to the extent the power is not needed for regulated retail service. MidAmerican Energy expects to invest approximately $1.44 billion in the three projects.

The first project is a natural gas-fired combined cycle unit with an estimated cost of $357 million, plus allowance for funds used during construction. MidAmerican Energy will own 100% of the plant and operate it. MidAmerican Energy has received a certificate from the IUB allowing it to construct the plant. Also, on May 29, 2002, the IUB issued an order that provides the ratemaking principles for

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the plant. Commercial operation of the simple cycle mode began on May 5, 2003. The plant will be operated in simple cycle mode during 2003 and 2004, resulting in approximately 327 MW of accredited capacity. The combined cycle operation is expected to commence in 2005, resulting in an expected additional 190 MW of accredited capacity.

The second project is currently under development and is expected to be a 790-MW (based on expected accreditation) super-critical-temperature, coal-fired plant fueled with low-sulfur coal. If constructed, MidAmerican Energy will operate the plant and expects to own approximately 475 MW of the plant. MidAmerican Energy expects to invest approximately $759 million in the project, plus allowance for funds used during construction. Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large base-load plants in Iowa. On January 23, 2003, MidAmerican Energy received an order approving the issuance of a certificate from the IUB allowing it to construct the plant. MidAmerican Energy also made a filing with the IUB for approval of ratemaking principles pertaining to this plant. On March 20, 2003, MidAmerican Energy entered into a settlement agreement with the Iowa Office of Consumer Advocate, related to the ratemaking principles application which agreement was subsequently filed with the IUB. On May 29, 2003, the IUB issued its order approving the ratemaking principles for this plant. On February 12, 2003, MidAmerican Energy executed a contract with Mitsui & Co. Energy Development, Inc. for the engineering, procurement and construction of the plant and issued a limited notice to proceed authorizing detailed engineering. A full notice to proceed authorizing construction is expected following the receipt of environmental and other required permits. Continued development of this project is subject to receiving orders from the IUB approving construction of the associated transmission facilities

The third project is currently under development and is expected to be wind power facilities totaling 310 MW based on the nameplate rating. Generally speaking, accredited capacity ratings for wind power facilities will likely fall within 15% to 20% of the nameplate ratings. If constructed, MidAmerican Energy will own and operate these facilities, which are expected to cost approximately $323 million, plus associated transmission facilities. MidAmerican Energy's plan to construct the wind project is in conjunction with a settlement proposal to extend through December 31, 2010, an electric rate freeze that is currently scheduled to expire at the end of 2005. The proposed settlement was filed with the IUB along with the related ratemaking principles application and is subject to approval by the IUB.

MidAmerican Energy is interconnected with Iowa utilities and utilities in neighboring states and is involved in an electric power pooling agreement known as MAPP. MAPP is a voluntary association of electric utilities doing business in Minnesota, Nebraska, North Dakota and the Canadian provinces of Saskatchewan and Manitoba and portions of Iowa, Montana, South Dakota and Wisconsin. Its membership also includes power marketers, regulatory agencies and independent power producers. MAPP facilitates operation of the transmission system and is responsible for the safety and reliability of the bulk electric system.

In November 2001, MAPPCOR, the contractor to MAPP, sold its transmission-related assets to the Midwest Independent Transmission System Operator, Inc., or Midwest ISO. The Midwest ISO now has responsibility for administration of MAPP's open-access transmission tariff.

Each MAPP participant is required to maintain for emergency purposes a net generating capability reserve of at least 15% above its system peak demand. If a participant's capability reserve falls below the 15% minimum, significant penalties could be contractually imposed by MAPP. MidAmerican Energy's reserve margin at peak demand for 2002 was approximately 21%.

MidAmerican Energy's transmission system connects its generating facilities with distribution substations and interconnects with 14 other transmission providers in Iowa and five adjacent states. Under normal operating conditions, MidAmerican Energy's transmission system is unconstrained and has adequate capacity to deliver energy to MidAmerican Energy's distribution system and to export and import significant levels of energy with other interconnected systems.

In December 1999, the FERC issued Order No. 2000 establishing, among other things, minimum characteristics and functions for regional transmission organizations. Public utilities that were not a

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member of an independent system operator at the time of the order were required to submit a plan by which its transmission facilities would be transferred to a regional transmission organization. On September 28, 2001, MidAmerican Energy and five other electric utilities filed with the FERC a plan to create TRANSLink Transmission Company LLC, or TRANSLink, and to integrate their electric transmission systems into a single, coordinated system operating as a for-profit independent transmission company in conjunction with a FERC-approved regional transmission organization. On April 25, 2002, the FERC issued an order approving the transfer of control of MidAmerican Energy and other utilities' transmission assets to TRANSLink in conjunction with TRANSLink's participation in the Midwest ISO regional transmission organization. Additionally, state regulatory approval is required in most states in which TRANSLink will be operating. MidAmerican Energy does not anticipate rulings in the state proceedings until some time in late 2003. Transferring the operations and control of MidAmerican Energy's transmission assets to other entities could increase costs for MidAmerican Energy; however, the actual impact of TRANSLink on MidAmerican Energy's future transmission costs is not yet known.

On July 31, 2002, the FERC issued a notice of proposed rulemaking with respect to "Standard Market Design" for the electric industry. The FERC initially characterized the proposal as portending "sweeping changes" to the use and expansion of the interstate transmission and wholesale bulk power systems in the United States. The proposal includes numerous proposed changes to the current regulation of transmission and generation facilities designed "to promote economic efficiency" and to replace the "obsolete patchwork we have today," according to the FERC Chairman. More recently, on April 28, 2003, the FERC issued a white paper describing how it intends to change the proposed rulemaking. The white paper, which uses the term "Wholesale Market Platform" in lieu of the term "Standard Market Design," indicates that a final rule may focus on the formation of regional transmission organizations and allow for regional differences. The proposed rule may impact the costs of our electricity and transmission products. A final rule is unlikely to be fully implemented until at least 2004. We are still evaluating the proposed rule and recognize there is uncertainty as to the timing and outcome of this rulemaking. Accordingly, the likely impact of the proposed rule on our transmission and generation businesses is unknown.

Gas Operations

For the year ended December 31, 2002, regulated gas sales by MidAmerican Energy, excluding transportation throughput, by customer class were as follows: 39.0% were to residential customers, 19.7% were to small general service customers, 1.5% were to large general service customers, 1.2% were to other customers, and 38.6% were wholesale sales. For the year ended December 31, 2002, regulated gas sales by MidAmerican Energy, excluding transportation throughput, by jurisdiction were as follows: 78.0% to Iowa, 11.2% to South Dakota, 10.0% to Illinois, and 0.8% to Nebraska.

MidAmerican Energy purchases gas supplies from producers and third party marketers. To ensure system reliability, a geographically diverse supply portfolio with varying terms and contract conditions is utilized for the gas supplies.

MidAmerican Energy has rights to firm pipeline capacity to transport gas to its service territory through direct interconnects to the pipeline systems of Northern Natural Gas, Natural Gas Pipeline Company of America, Northern Border Pipeline Company and ANR Pipeline Company. Firm capacity in excess of MidAmerican Energy's system needs, resulting from differences between the capacity portfolio and seasonal system demand, can be resold to other companies to achieve optimum use of the available capacity. Past IUB and South Dakota Public Utilities Commission rulings have allowed MidAmerican Energy to retain 30% of Iowa and South Dakota margins, respectively, earned on the resold capacity, with the remaining 70% being returned to customers through a purchased gas adjustment clause as described below.

MidAmerican Energy's cost of gas is recovered from customers through purchased gas adjustment clauses. In 1995, the IUB gave initial approval of MidAmerican Energy's Incentive Gas Supply Procurement Program. Under the program, as amended, MidAmerican Energy is required to file with the IUB every six months a comparison of its gas procurement costs to an index-based and historical reference price. If MidAmerican Energy's costs of gas for the period are less or greater than an

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established tolerance band around the reference price, then MidAmerican Energy shares a portion of the savings or costs with customers. In October 2002, the IUB approved a one-year extension of the program through October 31, 2003. A similar program is currently in effect in South Dakota through October 31, 2005. Since the implementation of the program, MidAmerican Energy has successfully achieved and shared savings with its natural gas customers.

MidAmerican Energy utilizes leased gas storage to meet peak day requirements and to manage the daily changes in demand due to changes in weather. The storage gas is typically replaced during the summer months. In addition, MidAmerican Energy also utilizes three liquefied natural gas plants and two propane-air plants to meet peak day demands.

MidAmerican Energy has strategically built multiple pipeline interconnections into several of its larger communities. Multiple pipeline interconnects create competition among pipeline suppliers for transportation capacity to serve those communities, thus reducing costs. In addition, multiple pipeline interconnects give MidAmerican Energy the ability to optimize delivery of the lowest cost supply from the various pipeline supply basins into these communities and increase delivery reliability. Benefits to MidAmerican Energy's system customers are shared with all jurisdictions through a consolidated purchased gas adjustment clause.

Kern River

Kern River's principal asset is an interstate natural gas transportation pipeline system comprising 1,678 miles of pipeline, with an approximate design capacity of 1,755,626 Dth per day, extending from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. Following the completion of several expansion projects, including the expansion for which Kern River filed an application with the FERC in Docket No. CP01-301-000 on November 15, 2000, or the 2002 Expansion Project, and the expansion for which Kern River filed an application with the FERC, in Docket No. CP01-106-000 on March 15, 2001, or the California Action Project, the design capacity of the pipeline was increased from its original capacity of 724,500 Dth per day to 870,000 Dth per day effective May 1, 2002. Of this amount, 21,000 Dth per day was temporarily used to serve California Action Project shippers but permanently reserved for the 2003 Expansion Project shippers. The 2003 Expansion Project, which was placed in service on May 1, 2003, increased the design capacity of Kern River's pipeline system by 885,626 Dth per day to 1,755,626 Dth per day. Kern River's pipeline is comprised of two sections: the mainline section and the common facilities. Kern River owns the entire mainline section, which extends from the pipeline's point of origination near Opal, Wyoming through the Central Rocky Mountains area into Daggett, California. The mainline section is comprised of the original 680 miles of 36-inch pipeline and 634.3 miles of 36-inch loop pipeline related to the 2003 Expansion Project.

The common facilities consist of a section of pipeline that extends from the point of interconnection with the mainline in Daggett to Bakersfield, California. The common facilities are jointly owned by Kern River (approximately 68.5% as of December 31, 2002) and Mojave Pipeline Company, or Mojave, a wholly owned subsidiary of El Paso Corporation (approximately 31.5% as of December 31, 2002), as tenants-in-common. Kern River's ownership percentage in the common facilities will increase or decrease pursuant to subsequently completed expansions by the respective joint owners, including the 2003 Expansion Project. Kern River has exclusive rights to approximately 1,570,500 Dth per day of the common facilities' capacity, and Mojave has exclusive rights to 400,000 Dth per day of capacity. Operation and maintenance of the common facilities are the responsibility of Mojave Pipeline Operating Company, an affiliate of Mojave. Mojave Pipeline Operating Company serves as operator and agent of the common facilities for Kern River and Mojave.

Transportation Service Agreements

Kern River has contracted 1,770,780 Dth per day of capacity under long-term firm gas transportation service agreements under which the pipeline receives natural gas on behalf of shippers at designated receipt points, transports the gas on a firm basis up to each shipper's maximum daily quantity and delivers thermally equivalent quantities of gas at designated delivery points. Primarily due to seasonal temperature variations, Kern River's contracted capacity exceeds its pipeline's design

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capacity by approximately 11,154 Dth per day. Each shipper pays Kern River the amount specified in its long-term firm gas transportation service agreement and Kern River's tariff, with such amount consisting primarily of a fixed monthly reservation fee based on each shipper's maximum daily quantity and a commodity charge based on the actual amount of gas transported.

With respect to Kern River's original mainline facilities and the 2002 Expansion Project, Kern River entered into 27 long-term firm gas transportation service agreements with 17 shippers, for a total of 864,154 Dth per day of capacity. All but one of these long-term firm gas transportation service agreements expires on or before April 30, 2017. Several of these shippers are major oil and gas companies, or affiliates of such companies. These shippers also include electric generating companies, energy marketing and trading companies, and a gas distribution utility which provides services in Nevada and California.

In connection with the 2003 Expansion Project, Kern River entered into 19 long-term firm gas transportation service agreements with 17 shippers, for a total of 902,626 Dth per day of capacity from Opal, Wyoming to delivery points primarily in California, commencing May 1, 2003. Approximately 85% of the capacity of the 2003 Expansion Project is contracted for 15 years, with 14 of the long-term firm gas transportation service agreements expiring on April 30, 2018. The remaining 15% of capacity is contracted for 10 years, with five long-term firm gas transportation service agreements expiring on April 30, 2013. Over 95% of the capacity of the 2003 Expansion Project has primary delivery points in California, with the flexibility to access secondary delivery points in Nevada and Utah. The design capacity for the 2003 Expansion Project is 885,626 Dth per day, which, together with the 21,000 Dth per day of capacity reserved for the 2003 Expansion Project from the California Action Project, equals the 906,626 Dth per day of capacity available for contract on the 2003 Expansion Project.

On May 1, 2003, Kern River Funding Corporation, a wholly owned subsidiary of Kern River, issued $836 million of its 4.893% Senior Notes with a final maturity on April 30, 2018. The proceeds were used to repay all of the approximately $815 million of outstanding borrowings under Kern River's $875 million credit facility. Kern River entered into this credit facility in 2002 to finance the construction of the 2003 Expansion Project.

Northern Natural Gas

Northern Natural Gas is one of the largest interstate natural gas pipeline systems in the United States. It reaches from Texas to Michigan's Upper Peninsula and is engaged in the transmission and storage of natural gas for utilities, municipalities, other pipeline companies, gas marketers, industrial and commercial users and other end users. Northern Natural Gas operates approximately 16,600 miles of natural gas pipelines with a design capacity of 4.4 Bcf per day that deliver approximately 5.0% of the total natural gas consumed in the United States. The Northern Natural Gas system is believed to be the largest in the United States as measured by pipeline miles and the eighth largest as measured by throughput. The pipeline system is powered by 92 transmission compressor stations with an aggregate of approximately 840,000 horsepower. Northern Natural Gas' storage services are provided through the operation of three underground storage fields (one in Iowa and two in Kansas) and two liquefied natural gas, or LNG, storage peaking units. The three underground natural gas storage facilities and Northern Natural Gas' two LNG storage peaking units have a total storage capacity of approximately 59 Bcf and over 1.3 Bcf per day of peak day deliverability. These storage facilities provide Northern Natural Gas with operational flexibility for daily balancing of its system and providing services to customers for meeting their year-round loadswing requirements. In 2002, approximately 11% of Northern Natural Gas' revenue was generated from storage services.

Northern Natural Gas' system is comprised of two distinct areas, its traditional end-use and distribution market area at the northern end of the system, including delivery points in Michigan, Illinois, Iowa, Minnesota, Nebraska, Wisconsin and South Dakota, which we refer to as the Market Area, and the natural gas supply and market area at the southern end of the system, including Kansas, Oklahoma, Texas and New Mexico, which we refer to as the Field Area. Northern Natural Gas' Field

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Area is interconnected with many interstate and intrastate pipelines in the national grid system. A majority of Northern Natural Gas' capacity in both the Market Area and the Field Area is dedicated to Market Area customers under long-term firm transportation contracts. Approximately 49% of Northern Natural Gas' capacity subject to firm transportation contracts is under contracts that extend beyond 2005.

The northern portion of Northern Natural Gas' pipeline system transports natural gas primarily to end-user and local distributor markets in the Market Area. Customers consist of LDCs, municipalities, other pipeline companies, gas marketers and end-users. While approximately ten large LDCs account for the majority of Market Area volumes, Northern Natural Gas also serves numerous small communities through these large LDCs as well as municipalities or smaller LDCs and directly serves several large end-users. In 2002, approximately 85% of Northern Natural Gas' revenue was from capacity charges under firm transportation and storage contracts and approximately 82% of that revenue was from LDCs. In 2002, approximately 68% of Northern Natural Gas' revenue was generated from Market Area customer contracts.

As noted above, the Field Area of Northern Natural Gas' system provides access to natural gas supply from key production areas such as the Hugoton, Permian and Anadarko Basins. In each of these areas, Northern Natural Gas has numerous interconnecting receipt and delivery points, with volumes received in the Field Area consisting of both directly connected supply and volumes from interconnections with other pipeline systems. In addition, Northern Natural Gas has the ability to aggregate processable natural gas for deliveries to various gas processing facilities.

In the Field Area, customers holding transportation capacity consist of LDCs, marketers, producers, and end-users. The majority of Northern Natural Gas' Field Area firm transportation is provided to Northern Natural Gas' Market Area firm customers under long-term firm transportation contracts with such volumes supplemented by volumes transported on an interruptible basis or pursuant to short-term firm contracts. In 2002, approximately 21% of Northern Natural Gas' revenue was generated from Field Area customer transportation contracts.

Northern Natural Gas' system is characterized by significant seasonal swings in demand, which provide opportunities to deliver high value-added services. Because of its location and multiple interconnections with other interstate and intrastate pipelines, Northern Natural Gas is able to access natural gas both from traditional production areas, such as the Hugoton, Permian and Anadarko Basins, as well as growing supply areas such as the Rocky Mountains through Trailblazer Pipeline Company, Pony Express Pipeline and Colorado Interstate Gas Company, and from Canadian production areas through Northern Border Pipeline Company, Great Lakes Gas Transmission Limited Partnership and Viking Gas Transmission Company. As a result of Northern Natural Gas' geographic location in the middle of the United States and its many interconnections with other pipelines, Northern Natural Gas augments its steady end-user and LDC revenue by taking advantage of opportunities to provide intermediate transportation through pipeline interconnections for customers in other markets including Chicago, other parts of the Midwest and Texas.

Northern Natural Gas' revenue is derived from the interstate transportation and storage of natural gas for third parties. Except for small quantities of natural gas owned for system operations, Northern Natural Gas does not own the natural gas that is transported through its system. Northern Natural Gas' transportation and storage operations are subject to a FERC-regulated tariff that is designed to allow it an opportunity to recover its costs together with a regulated return on equity.

Northern Natural Gas' strategic plan is focused on taking advantage of the system's bi-directional and relatively flexible natural gas transportation capabilities and its storage assets to maximize economic returns. A key component of this strategic plan is to build upon Northern Natural Gas' asset base located in the center of the North American natural gas grid by increasing flexibility through additional pipeline interconnects. Through existing interconnections, Northern Natural Gas' shippers have supply access to Canadian, Rocky Mountain, Hugoton, Anadarko and Permian supplies. Northern Natural Gas also expects to pursue selective pipeline expansions, storage service enhancement and improved utilization of existing systems. In addition, Northern Natural Gas is focused on utilizing its ability to transport both dry natural gas and processable natural gas to take

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advantage of opportunities presented by natural gas processing facility consolidations in the Mid-continent area. Northern Natural Gas expects to be able to meet the expected demand growth in its Market Area with only modest investment in new facilities as a result of the flexibility in Northern Natural Gas' system. Furthermore, Northern Natural Gas' access to supply diversity is expected to provide it with a significant competitive advantage because of the ability of the system to provide shippers access to many sources of low cost natural gas.

Kern River and Northern Natural Gas Competition

Natural gas competes with other forms of energy, including electricity, coal and fuel oil, primarily on the basis of price. Legislation and governmental regulations, the weather, the futures market, production costs, and other factors beyond the control of Kern River and Northern Natural Gas influence the price of natural gas. Industrial end-users often have the ability to choose from alternative fuel sources in addition to natural gas, such as fuel oil and coal.

Pipelines compete on the basis of cost, flexibility, reliability of service and overall customer service. More specifically, Kern River competes with various interstate pipelines and its shippers in serving the southern California, Las Vegas and Salt Lake City market areas, in order to market any unsubscribed capacity and expansion capacity. Kern River provides its customers with supply diversity through pipeline interconnects with Northwest Pipeline, Colorado Interstate Gas Pipeline, Overland Trail Pipeline, and Questar Pipeline. These interconnects allow Kern River to access natural gas reserves in Colorado, northwestern New Mexico, Wyoming, Utah and the Western Canadian Sedimentary Basin.

With respect to Kern River's original mainline facilities and the 2002 expansion, Kern River entered into transportation service agreements with 17 shippers. The transportation service agreements for a total of 864,154 Dth per day of capacity expire at various dates. Of the 27 service agreements with the 17 shippers, three agreements expire in 2011, one agreement expires in 2012, 19 agreements expire 2016, three agreements expire in 2017 and one agreement expires during 2018. In connection with the 2003 Expansion Project, Kern River entered into 19 long-term firm gas transportation service agreements with 17 shippers, for a total of 902,626 Dth per day of capacity from Opal, Wyoming to delivery points primarily in California, commencing May 1, 2003. Approximately 85% of the capacity of the 2003 Expansion Project is contracted for 15 years, with 14 of the long-term firm gas transportation service agreements expiring on April 30, 2018. The remaining 15% of capacity is contracted for 10 years, with five long-term firm gas transportation service agreements expiring on April 30, 2013.

Kern River is the only interstate pipeline that presently delivers natural gas directly from a gas supply basin into the intrastate California market, which enables its customers to avoid paying a "rate stack" (i.e., additional transportation costs attributable to the movement from one or more interstate pipeline systems to an intrastate system within California). We believe that Kern River's rate structure and access to upstream pipelines/storage facilities and to low-cost Rocky Mountain gas reserves increases its competitiveness and attractiveness to end-users. Kern River believes it is advantaged relative to other competing interstate pipelines because its relatively new pipeline can be expanded at lower costs and will require significantly less capital expenditure to comply with the Pipeline Safety Improvement Act of 2002 than other systems. Our levelized rate structures under expansion rates and settlement rates also provide our customers with greater rate certainty.

Historically, Northern Natural Gas has been able to provide competitive cost service because of its access to a variety of low cost supply basins, its cost control measures and its relatively high load factor through-put, which lowers the cost per unit of transportation. Although Northern Natural Gas has experienced pipeline system bypass affecting a small percentage of its market, to date Northern Natural Gas has been able to more than offset any load lost to bypass in the Market Area through expansion projects.

Major competitors in the Market Area include ANR Pipeline Company, Northern Border Pipeline Company and Natural Gas Pipeline Company of America. Other competitors include Great Lakes Gas Transmission Limited Partnership and Viking Gas Transmission Company. In the Field

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Area, Northern Natural Gas competes with a large number of other competitors. Particularly in the Field Area, a significant amount of Northern Natural Gas' capacity is used on an interruptible or short-term basis. In summer months, Northern Natural Gas' Market Area customers often release significant amounts of their unused firm capacity to other shippers, which competes with Northern Natural Gas' short-term or interruptible services.

Although Northern Natural Gas will need to aggressively compete to retain and build load, Northern Natural Gas believes that current and anticipated changes in its competitive environment have created opportunities to serve existing customers more efficiently and to meet certain growing supply needs. While LDCs provide peak day delivery growth driven by population growth and alternative fuel replacement, new off-peak demand growth is being driven primarily by power and ethanol plant expansion. Off-peak demand growth is important to Northern Natural Gas as this demand can generally be satisfied with little or no requirement for the construction of new facilities. Approximately 3,800 MW of natural gas-fired electric power plants in development have been announced in close proximity to Northern Natural Gas' system. Northern Natural Gas has been successful in competing for a significant amount of the increased demand related to the construction of new power and ethanol plants. Over the last five years, Northern Natural Gas has contracted approximately 430 mmcf per day of volume on its system from such new facilities, of which approximately 258 mmcf per day is currently in service and approximately 172 mmcf per day is scheduled to begin service between 2003 and 2005.

CE Electric UK

The business of CE Electric UK consists primarily of the distribution of electricity in the United Kingdom by Northern Electric and Yorkshire.

In December 1996, CE Electric UK Ltd., an indirect wholly owned subsidiary of CE Electric UK, acquired Northern Electric. Northern Electric was one of the twelve original United Kingdom regional electric companies that came into existence in 1990 as a result of the restructuring and subsequent privatization of the electricity industry that occurred in the United Kingdom. On September 21, 2001, CE Electric UK Ltd. acquired 94.75% of Yorkshire from Innogy Holdings plc, or Innogy, and simultaneously sold Northern Electric's electricity and gas supply and metering businesses to Innogy. We sometimes refer to these transactions as the Yorkshire Swap. In August 2002, CE Electric UK acquired the remaining 5.25% of Yorkshire that it did not already own from Xcel Energy International, an affiliate of Xcel Energy Inc.

With the acquisition of Yorkshire and the disposition of the electricity and gas supply and metering businesses of Northern Electric and certain other recent strategic dispositions, CE Electric UK is positioned to continue to bring together the skills and resources of two neighboring distribution businesses to create one of the largest distribution companies in the United Kingdom, serving more than 3.6 million customers in an area of approximately 10,000 square miles. CE Electric UK has also implemented a number of initiatives that have produced savings in ongoing operating and capital costs at its businesses.

Descriptions of the functional business units of each of Northern Electric's and Yorkshire's distribution businesses are set forth below.

Electricity Distribution

Northern Electric's and Yorkshire's operations consist primarily of the distribution of electricity and other auxiliary businesses in the United Kingdom. Northern Electric's and Yorkshire's distribution licensee companies, Northern Electric Distribution Limited, or NEDL, and Yorkshire Electricity Distribution plc, or YEDL, respectively, receive electricity from the national grid transmission system and distribute it to their customers' premises using their network of transformers, switchgear and cables. Substantially all of the customers in NEDL's and YEDL's distribution service areas are connected to the NEDL and YEDL networks and electricity can only be delivered through their distribution system, thus providing NEDL and YEDL with distribution volume that is relatively stable from year to year. NEDL and YEDL charge fees for the use of the distribution system to the

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suppliers of electricity. The suppliers, which purchase electricity from generators and sell the electricity to end-user customers, use NEDL's and YEDL's distribution networks pursuant to an industry standard "Use of System Agreement" which NEDL and YEDL separately entered into with the various suppliers of electricity in their respective distribution areas. The fees that may be charged by NEDL and YEDL for use of their distribution systems are controlled by a prescribed formula that limits increases (and may require decreases) based upon the rate of inflation in the United Kingdom and other regulatory action.

At December 31, 2002, NEDL's and YEDL's electricity distribution network (excluding service connections to consumers) on a combined basis included approximately 31,000 kilometers of overhead lines and approximately 65,000 kilometers of underground cables. In addition to the circuits referred to above, at December 31, 2002, NEDL's and YEDL's distribution facilities also included approximately 57,000 transformers and approximately 58,000 substations. Substantially all substations are owned in freehold and most of the balance are held on leases that will not expire within 10 years.

Utility Services

Integrated Utility Services Limited, a subsidiary of Northern Electric, is an engineering contracting company whose main business is providing electrical connection services on behalf of NEDL's and YEDL's distribution businesses and providing electrical infrastructure contracting services to third parties.

Gas Exploration and Production

CE Gas, our indirect subsidiary, is a gas exploration and production company that is focused on developing integrated upstream gas projects. Its upstream gas business consists of the exploration, development and production, including transportation and storage, of gas for delivery to a point of sale into either a gas supply market or a power generation facility.

In May 2002, CE Gas executed the sale of several of its United Kingdom natural gas assets to Gaz de France for £137.0 million (approximately $200.0 million). CE Gas sold four natural gas-producing fields located in the southern basin of the United Kingdom North Sea, including Anglia, Johnston, Schooner and Windermere. The transaction also included the sale of rights in four gas fields (in development/construction) and three exploration blocks owned by CE Gas.

In addition to retaining its interest in the Victor Field, which is a gas field located in the North Sea, and the ETS pipeline, which is a gas pipeline that extends from the North Sea to gas terminals in the United Kingdom. CE Gas retained certain development interests in Poland (Polish Trough) and Australia (Perth, Bass and Otway Basins).

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CalEnergy Generation – Domestic

Business

Through CalEnergy Generation – Domestic, we own interests in 15 operating non-utility power projects in the United States. The following table sets out certain information concerning CalEnergy – Domestic's non-utility power projects in operation as of March 31, 2003:


Operating Project Facility Net
Capacity (MW)(1)		 Net MW
Owned(1)		 Fuel Location Power
Purchase
Agreement
Expiration		 Power
Purchaser(2)
Cordova   537     537   Gas Illinois 2017 El Paso/MidAmerican Energy
Salton Sea I   10     5   Geo California 2017 Edison
Salton Sea II   20     10   Geo California 2020 Edison
Salton Sea III   50     25   Geo California 2019 Edison
Salton Sea IV   40     20   Geo California 2026 Edison
Salton Sea V   49     25   Geo California Year-to-year TransAlta/Minerals(3)
Vulcan   34     17   Geo California 2016 Edison
Elmore   38     19   Geo California 2018 Edison
Leathers   38     19   Geo California 2019 Edison
Del Ranch   38     19   Geo California 2019 Edison
CE Turbo   10     5   Geo California Year-to-year TransAlta/Minerals(3)
Saranac   240     90   Gas New York 2009 NYSE&G
Power Resources   200     100   Gas Texas 2003 TXU
Yuma   50     25   Gas Arizona 2024 SDG&E
Roosevelt Hot
Springs(4)		   23     17   Geo Utah Year-to-year UP&L
Domestic Operating Projects   1,377     933  
(1) Represents accredited net generating capability. Actual MW may vary depending on operating conditions and plant design. Net MW owned indicates current legal ownership, but, in some cases, does not reflect the current allocation of partnership distributions.
(2) El Paso Corporation, or El Paso; TransAlta USA Inc, or TransAlta; Southern California Edison Company, or Edison; CalEnergy Minerals LLC, or Minerals, a zinc facility owned by a subsidiary of MEHC; New York State Electric & Gas Corporation, or NYSE&G; TXU Generation Company LP, or TXU; San Diego Gas & Electric Company, or SDG&E; and Utah Power & Light Company, or UP&L.
(3) Each contract governing power purchases by Minerals will expire 33 years from the date of the initial power delivery under such contract. Pursuant to a Transaction Agreement dated January 29, 2003, Salton Sea Power LLC, or Salton Sea Power, and CE Turbo LLC, or CE Turbo, began selling available power to TransAlta, on February 12, 2003 based on percentages of the Dow Jones SP-15 Index. Such agreement will expire on October 31, 2003.
(4) Intermountain Geothermal Company, our subsidiary, owns an approximately 70% indirect interest in this project which supplies geothermal steam to a power plant owned by UP&L. We obtained a cash prepayment under a pre-sale agreement with UP&L whereby UP&L paid in advance for the steam produced by this steam field.

Cordova Energy owns a 537 MW gas-fired power plant in the Quad Cities, Illinois area that we refer to as the Cordova Project. CalEnergy Generation Operating Company, its indirect wholly owned subsidiary, operates the Cordova Project. The Cordova Project commenced commercial operations in June 2001. Cordova Energy entered into a power purchase agreement with a unit of El Paso, under which El Paso will purchase all of the capacity and energy from the project until December 31, 2019. Cordova Energy has exercised an option to recall from El Paso 50% of the output through May 14,

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2004, reducing El Paso's purchase obligation to 50% of the output during such period. The recalled output is being sold to MidAmerican Energy. We are aware there have been public announcements that El Paso's financial condition has deteriorated as a result of, among other things, reduced liquidity. We will continue to monitor the situation.

We have a 50% ownership interest in CE Gen, whose affiliates currently operate ten geothermal plants, or the Imperial Valley Projects, in the Imperial Valley in California. The Salton Sea Projects consist of the Salton Sea I, Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V Projects, or the Salton Sea I Project, the Salton Sea II Project, the Salton Sea III Project, the Salton Sea IV Project, and the Salton Sea V Project, respectively. The Partnership Projects consist of the Vulcan, Elmore, Leathers, Del Ranch and CE Turbo projects, or the Vulcan Project, the Elmore Project, the Leathers Project, the Del Ranch Project, and the CE Turbo Project, respectively.

Each of the Imperial Valley Projects, excluding the Salton Sea V and CE Turbo Projects, sells electricity to Edison pursuant to a separate Standard Offer No. 4 Agreement, or SO4 Agreement, or a negotiated power purchase agreement. Each power purchase agreement is independent of the others, and the performance requirements specified within one such agreement apply only to the project, which is subject to the agreement. The power purchase agreements provide for energy payments, capacity payments and capacity bonus payments. Edison makes fixed annual capacity payments and capacity bonus payments to the applicable projects to the extent that capacity factors exceed certain benchmarks. The price for capacity was fixed for the life of the SO4 Agreements and is significantly higher in the months of June through September.

Energy payments for the SO4 Agreements were at increasing fixed rates for the first ten years after firm operation and thereafter at a rate based on the cost that Edison avoids by purchasing energy from the project instead of obtaining the energy from other sources, or Avoided Cost of Energy. In June and November 2001, the Imperial Valley Projects, which receive Edison's Avoided Cost of Energy, entered into agreements that provide for amended energy payments under the SO4 Agreements. The amendments provide for fixed energy payments per kWh in lieu of Edison's Avoided Cost of Energy. The fixed energy payment was 3.25 cents per kWh from December 1, 2001 through April 30, 2002 and is 5.37 cents per kWh commencing May 1, 2002 for a five-year period. Following the five-year period, the energy payments revert back to Edison's Avoided Cost of Energy.

For the years ended December 31, 2002, 2001 and 2000, respectively, Edison's Average Avoided Cost of Energy was 3.5 cents per kWh, 7.4 cents per kWh and 5.8 cents per kWh, respectively. Estimates of Edison's future Avoided Cost of Energy vary substantially from year to year.

The Salton Sea V and CE Turbo projects began operations in 2000 and, when the Zinc Recovery Project (defined below) achieves 100% production, the Salton Sea V Project and the CE Turbo Project would expect to sell approximately 22 MW to the Zinc Recovery Project at a price based on market transactions. Commencing June 1, 2003, the Salton Sea V project will also sell approximately 20 MW to the City of Riverside's municipally-owned utility at $61 per MW pursuant to a 10-year power purchase contract. The remainder is being sold through other market transactions.

The Saranac Project is a 240 net MW natural gas-fired cogeneration facility located in Plattsburgh, New York. The Saranac Project has entered into a 15-year power purchase agreement with NYSE&G expiring in 2009. The Saranac Project is a qualifying facility, or QF, and has entered into 15-year steam purchase agreements with Georgia-Pacific Corporation and Pactiv Corporation. The Saranac Project has a 15-year natural gas supply agreement with Shell Canada Limited, to supply 100% of the Saranac Project's fuel requirements. Each of the Saranac Project's power purchase agreements, the Saranac Project's steam purchase agreements and the Saranac Project's gas supply agreements contain rates that are fixed for their respective contract terms. Revenues escalate at a higher rate than fuel costs. The Saranac partnership is indirectly owned by subsidiaries of CE Gen, ArcLight Capital Partners LLC and General Electric Capital Corporation.

The Power Resources Project is a 200 net MW natural gas-fired cogeneration project located near Big Spring, Texas, which has a 15-year power purchase agreement with TXU, formerly known as Texas Utilities Electric Company, expiring in September 2003. The Power Resources Project is a QF

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and has a steam purchase agreement with ALON USA, L.P. On December 30, 2002, Power Resources obtained an exempt wholesale generator order from the FERC. The status as an exempt wholesale generator would facilitate the Power Resources Project sale of energy in market transactions.

The Yuma Project is a 50 net MW natural gas-fired cogeneration project in Yuma, Arizona providing 50 MW of electricity to SDG&E under an existing 30-year power purchase agreement which expires in 2024. The Yuma Project is a QF and has executed steam sales contracts with an adjacent industrial entity to act as its thermal host.

The Roosevelt Hot Springs Project is a geothermal steam field which supplies geothermal steam to a 23 net MW power plant owned by UP&L located on the Roosevelt Hot Springs property under a 30-year steam sales contract expiring in 2020. We obtained a cash prepayment under a pre-sale agreement with UP&L whereby UP&L paid in advance for the steam produced by the steam field. We guarantee the performance of this subsidiary. We must make certain penalty payments to UP&L if the steam produced does not meet certain quantity and quality requirements.

Zinc Recovery Project

Minerals developed and owns the rights to proprietary processes for the extraction of zinc from elements in solution in the geothermal brine and fluids utilized at the Imperial Valley Projects. A plant has successfully produced commercial quality zinc at the projects. The affiliates of Minerals may develop facilities for the extraction of manganese, silica and other products as they further develop the extraction technology.

Minerals constructed the Zinc Recovery Project, which is recovering zinc from geothermal brine. Facilities have been installed near the Imperial Valley Projects sites to extract a zinc chloride solution from the geothermal brine through an ion exchange process. This solution is being transported to a central processing plant where zinc ingots are being produced through solvent extraction, electrowinning and casting processes. The Zinc Recovery Project is designed to have a capacity of approximately 30,000 metric tons per year. Limited production began during December 2002 and full production is expected by late-2003. In September 1999, Minerals entered into a sales agreement whereby all high-grade zinc produced by the Zinc Recovery Project will be sold to Cominco, Ltd. The initial term of the agreement expires in December 2005.

Development Projects

Our subsidiary, CE Obsidian Energy LLC, or Obsidian, is evaluating the development of a 185 net MW geothermal facility in Imperial Valley, California. Substantially all the output of the facility will be sold to the Imperial Irrigation District pursuant to a power purchase agreement. TransAlta has elected to participate in the ownership and development of this project at a level of 50%. On July 29, 2002, Obsidian filed an application for certification seeking approval from the California Energy Commission to construct and operate the facility.

CalEnergy Generation – Foreign

Business

We indirectly own the Upper Mahiao, Mahanagdong and Malitbog projects, which are geothermal power plants located on the island of Leyte in the Philippines, and the Casecnan Project, a combined irrigation and hydroelectric power generation project, which is located in the central part of Island of Luzon in the Philippines. Each plant possesses an operating margin that allows for production in excess of the amount listed below. Utilization of this operating margin is based upon a variety of factors and can be expected to vary between calendar quarters under normal operating conditions.

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Operating Projects

The following table sets out certain information concerning CalEnergy Generation – Foreign's non-utility power projects in operation as of March 31, 2003:


Operating Project(1) Facility Net
Capacity (MW)(2)		 Net MW
Owned(2)		 Fuel Commercial
Operation		 Power Purchaser/
Guarantor(3)
Upper Mahiao   119     119   Geo 1996 PNOC-EDC/ROP
Mahanagdong   165     155   Geo 1997 PNOC-EDC/ROP
Malitbog   216     216   Geo 1996-97 PNOC-EDC/ROP
Casecnan(4)   150     150   Hydro 2001 NIA/ROP
International Operating Projects   650     640  
(1) All operating projects are located in the Philippines; all operating projects are governed by contracts which are payable in U.S. dollars; and all operating projects carry political risk insurance.
(2) Actual MW may vary depending on operating and reservoir conditions and plant design. Facility Net Capacity (MW) represents the contract capacity for the facility. Net MW owned indicates current legal ownership, but, in some cases, does not reflect the current allocation of distributions.
(3) PNOC-Energy Development Corporation, or PNOC-EDC, ROP, and NIA (NIA also purchases water from this facility). The ROP government's undertaking supports PNOC-EDC's and NIA's respective obligations.
(4) Net MW Owned is subject to repurchase rights of up to 15% of the project by an initial minority shareholder and a dispute with the other initial minority shareholder regarding an additional 15% of the project. Also see "Legal Proceedings — Philippines."

The Upper Mahiao project is a 119 net MW geothermal power project owned and operated by CE Cebu Geothermal Power Company, Inc., or CE Cebu, a Philippine corporation that is 100% indirectly owned by us. The Upper Mahiao facility has been in commercial operation since June 17, 1996.

Under the terms of the Upper Mahiao energy conversion agreement, CE Cebu owns and operates the Upper Mahiao Project during the ten-year cooperation period, which commenced in June 1996, after which ownership will be transferred to PNOC-EDC at no cost.

The Upper Mahiao Project is located on land provided by PNOC-EDC at no cost. The project takes geothermal steam and fluid, also provided by PNOC-EDC at no cost, and converts its thermal energy into electrical energy which is sold to PNOC-EDC on a "take-or-pay" basis, which in turn sells the power to the NPC for distribution on the island of Cebu. PNOC-EDC pays to CE Cebu a fee based on the plant capacity nominated to PNOC-EDC in any year (which, at the plant's design capacity, is approximately 95% of total contract revenue) and a fee based on the electricity actually delivered to PNOC-EDC (approximately 5% of total contract revenue). Payments under the Upper Mahiao agreement are denominated in U.S. dollars, or computed in U.S. dollars and paid in pesos at the then-current exchange rate, except for the energy fee. PNOC-EDC's payment requirements, and its other obligations under the Upper Mahiao agreement, are supported by the ROP through a performance undertaking.

The Mahanagdong Project is a 165 net MW geothermal power project owned and operated by CE Luzon Geothermal Power Company, Inc., or CE Luzon, a Philippine corporation of which we indirectly own 100% of the common stock. Another industrial company owns an approximate 6% preferred equity interest in the Mahanagdong Project. The Mahanagdong Project has been in commercial operation since July 25, 1997. The Mahanagdong Project sells 100% of its capacity on a similar basis as described above for the Upper Mahiao Project to PNOC-EDC, which in turn sells the power to the NPC for distribution on the island of Luzon.

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The terms of the Mahanagdong energy conversion agreement are substantially similar to those of the Upper Mahiao agreement. The Mahanagdong agreement provides for a ten-year cooperation period. At the end of the cooperation period, the facility will be transferred to PNOC-EDC at no cost. All of PNOC-EDC's obligations under the Mahanagdong agreement are supported by the ROP through a performance undertaking. The capacity fees are approximately 97% of total revenue at the design capacity levels and the energy fees are approximately 3% of such total revenue. PNOC-EDC's payment requirements, and its other obligations under the Mahanagdong agreement, are supported by the ROP through a performance undertaking.

The Malitbog Project is a 216 net MW geothermal project owned and operated by Visayas Geothermal Power Company, or VGPC, a Philippine general partnership that is wholly owned, indirectly, by us. The three units of the Malitbog facility were put into commercial operation on July 25, 1996 (for Unit I) and July 25, 1997 (for Units II and III). VGPC sells 100% of its capacity on substantially the same basis as described above for the Upper Mahiao Project to PNOC-EDC, which sells the power to the NPC for distribution on the islands of Cebu and Luzon.

The electrical energy produced by the facility is sold to PNOC-EDC on a take-or-pay basis. These capacity payments equal approximately 100% of total revenue. A substantial majority of the capacity payments are required to be made by PNOC-EDC in dollars. The portion of capacity payments payable to PNOC-EDC in pesos is expected to vary over the term of the Malitbog energy conversion agreement from 10% of VGPC's revenue in the early years of the 10-year cooperation period to 23% of VGPC's revenue at the end of the cooperation period. Payments made in pesos will generally be made to a peso-dominated account and will be used to pay peso-denominated operation and maintenance expenses with respect to the Malitbog Project and Philippine withholding taxes, if any, on the Malitbog Project's debt service. The government of the Philippines has entered into a performance undertaking, which provides that all of PNOC-EDC's obligations pursuant to the Malitbog energy conversion agreement carry the full faith and credit of, and are affirmed and guaranteed by, the ROP.

The Malitbog energy conversion agreement cooperation period expires ten years after the date of commencement of commercial operation of Unit III. At the end of this cooperation period, the facility will be transferred to PNOC-EDC at no cost, on an "as is" basis. See "Legal Proceedings — Philippines" for a description of legal proceedings related to the Malitbog Project.

CE Casecnan, our indirectly majority owned subsidiary, operates the Casecnan Project, a combined irrigation and 150 Net MW hydroelectric power generation project. The Casecnan Project consists generally of diversion structures in the Casecnan and Taan rivers that capture and divert excess water in the Casecnan watershed by means of concrete, in-stream diversion weirs and transfer that water through a transbasin tunnel of approximately 23 kilometers (including the intake adit from the Taan to the Casecnan river), with a diameter of approximately 6.5 meters to an existing underutilized water storage reservoir at Pantabangan. During the water transfer, the elevation differences between the two watersheds allows electrical energy to be generated at a 150 MW rated capacity power plant, which is located in an underground powerhouse cavern at the end of the water tunnel. A tailrace discharge tunnel of approximately three kilometers delivers water from the water tunnel and the new powerhouse to the Pantabangan reservoir, providing additional water for irrigation and increasing the potential electrical generation at two downstream existing hydroelectric facilities of the NPC, the government-owned and controlled corporation that is the primary supplier of electricity in the Philippines. Since the water has been determined to remain suitable for irrigation throughout the Casecnan Project operations of capturing, diverting and transferring the water, other than removing sediments at the diversion structures, no treatment is required. Once in the reservoir at Pantabangan, the water is under the control of, and for the use of the NIA.

CE Casecnan constructed and operates the Casecnan Project under the terms of the Project Agreement between CE Casecnan and NIA. Under the Project Agreement, CE Casecnan developed, financed and constructed the Casecnan Project during the construction period and will own and operate the Project during the 20-year Cooperation Period. During the Cooperation Period, NIA is obligated to accept all deliveries of water and energy, and so long as the Casecnan Project is physically capable of operating and delivering in accordance with agreed levels set forth in the Project

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Agreement, NIA will pay CE Casecnan a fixed fee for the delivery of water and a fixed fee for the delivery of a threshold amount of electricity. In addition, NIA will pay a fee for all electricity delivered in excess of the threshold amount up to a specified amount. The water delivery fee is a fixed monthly amount, to be received in US dollars at the end of each month, based on 801.9 million cubic meters of water flow past the water delivery point per year, pro-rated to 66.8 million cubic meters per month. The unit price for water is established at $0.029 per cubic meter (subject to adjustment as set forth in the Project Agreement) as of January 1, 1994 and escalated at seven and one-half percent (7.5%) per annum, pro-rated on a monthly basis, through the end of the fifth year of the Cooperation Period and then kept flat at that level for the last fifteen years of the Cooperation Period. The unit price for water is to be adjusted by $.00043 for each $1.0 million of certain taxes and fees paid by us as specified in the Project Agreement. The unit price of water as of December 31, 2002 is $0.1017. Actual deliveries of water greater than or less than 66.8 million cubic meters in any month will not result in any adjustment of the water delivery fee. The guaranteed energy fee is a fixed monthly amount, to be received in US dollars at the end of each month, based on energy deliveries of 228.0 million kWh per year, pro-rated to 19.0 million kWh per month. Actual deliveries of energy less than 19.0 million kWh per month will not result in any reduction of the guaranteed energy fee but will result in an adjustment to the excess energy fee. The unit price for guaranteed energy is $0.1596 per kWh. The excess energy fee is a variable amount, to be received in US dollars at the end of each month, for electrical energy delivered in that month in excess of 19.0 million kWh. No excess energy delivery fee will be due until all cumulative electrical energy shortfalls below 19.0 million kWh in previous months have been made up. The unit price of excess energy is $0.1509 per kWh. NIA will sell the electricity it purchases to NPC, although NIA's obligations to CE Casecnan under the Project Agreement are not dependent on NPC's purchase of the electricity from NIA. All fees to be paid by NIA to CE Casecnan are payable in US dollars. The fixed fees paid for the delivery of water and energy, regardless of the amount of electricity or water actually delivered, are expected to provide approximately 78% of CE Casecnan's revenues. At the end of the Cooperation Period, the Casecnan Project will be transferred to NIA at no additional consideration on an "as is" basis.

The ROP has provided a performance undertaking under which NIA's obligations under the Project Agreement are guaranteed by the full faith and credit of the ROP. The Project Agreement and the performance undertaking provide for the resolution of disputes by binding arbitration in Singapore under international arbitration rules.

HomeServices

Business

HomeServices is the second largest full-service independent residential real estate brokerage firm in the United States. In addition to providing traditional residential real estate brokerage services, HomeServices offers other integrated real estate services, including mortgage originations, title and closing services and other related services. HomeServices currently operates in 15 states under the following brand names: Carol Jones Realty, CBSHOME Real Estate, Champion Realty, Edina Realty HomeServices, First Realty/GMAC, Home Real Estate, Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty, Prudential California Realty, RealtySouth, Rector Hayden Realtors, Reece & Nichols, Semonin REALTORS and Woods Bros. Realty. HomeServices generally occupies the number one or number two market share position in each of its major markets based on aggregate closed transaction sides. HomeServices' major markets consist of the following metropolitan areas: Minneapolis and St. Paul, Minnesota; Los Angeles and San Diego, California; Kansas City, Kansas; Des Moines, Iowa; Omaha and Lincoln, Nebraska; Birmingham, Alabama; Tucson, Arizona; Louisville and Lexington, Kentucky; Annapolis, Maryland; Atlanta, Georgia and Springfield, Missouri.

HomeServices' 2002 Acquisitions

In 2002, HomeServices separately acquired three real estate companies. For the year ended December 31, 2001, these real estate companies had combined revenue of approximately $356.0 million on 42,000 closed sides representing $13.7 billion of sales volume.

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Properties

Our utility properties consist of physical assets necessary and appropriate to render electric and gas service in our service territories. Electric property consists primarily of generation, transmission and distribution facilities. Gas property consists primarily of distribution plants, natural gas pipelines, related rights-of-way, compressor stations and meter stations. It is the opinion of management that the principal depreciable properties owned by us are in good operating condition and well maintained.

MidAmerican Energy

MidAmerican Energy's most significant properties are its electric generation facilities. For a discussion of these generation facilities, please see "Business — MidAmerican Energy." MidAmerican Energy's utility properties consist of physical assets necessary and appropriate to render electric and gas service in its service territories. Electric property consists primarily of generation, transmission and distribution facilities. Gas property consists primarily of natural gas mains and services pipelines, meters and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. It is the opinion of management that the principal depreciable properties owned by MidAmerican Energy are in good operating condition and well maintained.

The electric transmission system of MidAmerican Energy at December 31, 2002, included 290 miles of 345-kV lines and 1,111 miles of 161-kV lines. MidAmerican Energy's electric distribution system included approximately 218,500 transformers and 377 substations at December 31, 2002.

The gas distribution facilities of MidAmerican Energy at December 31, 2002, included 20,835 miles of gas mains and services.

Substantially all the former Iowa-Illinois Gas and Electric Company utility property and franchises, and substantially all of the former Midwest Power Systems electric utility property located in Iowa, or approximately 80% of gross utility plant, is pledged to secure mortgage bonds.

CE Electric UK

At December 31, 2002, Northern Electric's and Yorkshire's electricity distribution networks (excluding service connection to consumers) on a combined basis included approximately 31,000 kilometers of overhead lines and approximately 65,000 kilometers of underground cables. In addition to the circuits referred to above, at December 31, 2002, Northern Electric's and Yorkshire's distribution facilities also included approximately 57,000 transformers and approximately 58,000 substations.

Kern River and Northern Natural Gas

At May 1, 2003, Kern River's pipeline was comprised of two distinguishable sections: the mainline and the common facilities. The mainline section is comprised of the original 680 miles of 36-inch pipeline and 634.3 miles of 36-inch loop pipeline, and extends from the pipeline's point of origination in Opal, Wyoming through the Central Rocky Mountains area to Daggett, California and is owned entirely by Kern River. The common facilities consist of the 219-mile section of pipeline that extends from Daggett to Bakersfield, California. The common facilities are jointly owned by Kern River (currently approximately 68.5%) and Mojave (currently approximately 31.5%) as tenants-in-common.

At December 31, 2002, Northern Natural Gas' system was comprised of approximately 7,300 miles of mainline transmission pipes and approximately 9,300 miles of smaller diameter branch lines and laterals. Northern Natural Gas' storage services are provided through the operation of three underground storage fields, in Redfield, Iowa, and Lyons and Cunningham, Kansas. The three underground natural gas storage facilities and Northern Natural Gas' two liquefied natural gas storage peaking units have a total storage capacity of approximately 59 Bcf. Northern Natural Gas' two LNG liquefaction/vaporization facilities are located near Garner, Iowa and Wrenshall, Minnesota with storage capacity of 2 Bcf each.

The right to construct and operate the pipelines across certain property was obtained through negotiations and through the exercise of the power of eminent domain, where necessary. Kern River

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and Northern Natural Gas continue to have the power of eminent domain in each of the states in which they operate their respective pipelines, but they do not have the power of eminent domain with respect to Native American tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management.

With respect to real property, each of the pipelines falls into two basic categories: (1) parcels that are owned in fee, such as certain of the compressor stations, measurement stations and district office sites; and (2) parcels where the interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the pipelines.

We believe that Kern River and Northern Natural Gas each have satisfactory title to all of the real property making up their respective pipelines in all material respects.

Other Properties

At March 31, 2003, our most significant physical properties, other than those owned by MidAmerican Energy, CE Electric UK, Kern River and Northern Natural Gas, are our current interests in operating power facilities and our plants under construction and related real property interests, as well as leases of office space for our residential real estate brokerage operations. See "Business" for further detail.

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REGULATION

Our operating platforms are subject to a number of federal, state, local and international regulations.

MidAmerican Energy

MidAmerican Energy is subject to comprehensive regulation by the FERC as well as utility regulatory agencies in Iowa, Illinois and South Dakota that significantly influences the operating environment and the recoverability of costs from utility customers. Except for Illinois, that regulatory environment has to date, in general, given MidAmerican Energy an exclusive right to serve electricity customers within its service territory and, in turn, the obligation to provide electric service to those customers. In Illinois all customers are free to choose their electricity provider. MidAmerican Energy has an obligation to serve customers at regulated rates that leave MidAmerican Energy's system, but later choose to return. To date, there has been no significant loss of customers from MidAmerican Energy's existing regulated Illinois rates.

In connection with the March 1999 approval by the IUB of the MidAmerican Energy acquisition and March 2000 affirmation as part of our acquisition by a private investor group, MidAmerican Energy agreed, among other things, to use all commercially reasonable efforts to maintain an investment grade credit rating for MidAmerican Energy's utility operations and its long-term debt and to seek the approval of the IUB of a reasonable utility capital structure if MidAmerican Energy's utility operations' common equity level decreases below 42%, excluding circumstances beyond its control, or below 39%, under any circumstances. MidAmerican Energy's utility operations' common equity level at December 31, 2002 and 2001, was above these levels.

With the elimination of its energy adjustment clause in Iowa in 1997, MidAmerican Energy is financially exposed to movements in energy prices. Although MidAmerican Energy has sufficient low cost generation under typical operating conditions for its retail electric needs, a loss of adequate generation by MidAmerican Energy requiring the purchase of replacement power at a time of high market prices could subject MidAmerican Energy to losses on its energy sales.

In December 1999, the FERC issued Order No. 2000 establishing, among other things, minimum characteristics and functions for regional transmission organizations. Public utilities that were not a member of an independent system operator at the time of the order were required to submit a plan by which their transmission facilities would be transferred to a regional transmission organization. On September 28, 2001, MidAmerican Energy and five other electric utilities filed with the FERC a plan to create TRANSLink and to integrate their electric transmission systems into a single, coordinated system operating as a for-profit independent transmission company in conjunction with a FERC approved regional transmission organization. On April 25, 2002, the FERC issued an order approving the transfer of control of MidAmerican Energy's and other utilities' transmission assets to TRANSLink in conjunction with TRANSLink's participation in the Midwest ISO. Additionally, state regulatory approval is required from most states in which TRANSLink will be operating, MidAmerican Energy does not anticipate rulings in the state proceedings until some time in late 2003. Transferring operation and control of MidAmerican Energy's transmission assets to other entities could increase costs for MidAmerican Energy; however, the actual impact of TRANSLink on MidAmerican Energy's future transmission costs is not yet known.

On July 31, 2002, the FERC issued a notice of proposed rulemaking with respect to "Standard Market Design" for the electric industry. The FERC initially characterized the proposal as portending "sweeping changes" to the use and expansion of the interstate transmission and wholesale bulk power systems in the United States. The proposal includes numerous proposed changes to the current regulation of transmission and generation facilities designed "to promote economic efficiency" and to replace the "obsolete patchwork we have today," according to the FERC Chairman. More recently, on April 28, 2003, the FERC issued a white paper describing how it intends to change the proposed rulemaking. The white paper, which uses the term "Wholesale Market Platform" in lieu of the term "Standard Market Design," indicates that a final rule may focus on the formation of regional transmission organizations and allow for regional differences. The proposed rule may impact the costs

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of our electricity and transmission products. A final rule is unlikely to be fully implemented until at least 2004. We are still evaluating the proposed rule and recognize there is uncertainty as to the timing and outcome of this rulemaking. Accordingly, the likely impact of the proposed rule on our transmission and generation businesses is unknown.

The structure of such federal and state energy regulations have in the past, and may in the future, be the subject of various challenges and restructuring proposals by utilities and other industry participants. The implementation of regulatory changes in response to such changes or restructuring proposals, or otherwise imposing more comprehensive or stringent requirements on MidAmerican Energy which would result in increased compliance costs, could have a material adverse effect on its results of operations.

Under a settlement agreement approved by the IUB on December 21, 2001, MidAmerican Energy's Iowa retail rates in effect on December 31, 2000 are frozen through December 31, 2005. In approving that settlement, the IUB specifically allows the filing of the electric rate design and/or cost of service rate changes that are intended to keep overall company revenue unchanged but could result in changes to individual tariffs. The 2001 settlement agreement further provides that an amount equal to 50% of revenues associated with Iowa retail electric returns on equity between 12% and 14%, and 83.33% of revenues associated with Iowa retail electric returns on equity above 14%, in each year is recorded as a regulatory liability to be used to offset a portion of the cost to Iowa customers of future generating plant investment. An amount equal to the regulatory liability is recorded as a regulatory charge in depreciation and amortization expense when the liability is accrued. Interest expense is accrued on the portion of the regulatory liability related to prior years. Beginning in 2002, the liability is being reduced as it is credited against allowance for funds used during construction or capitalized financing costs associated with generating plant additions. As of March 31, 2003 and December 31, 2002, the related regulatory liability was $117.4 million and $102.9 million, respectively.

On March 20, 2003, MidAmerican Energy and the Iowa Office of Consumer Advocate agreed upon a settlement proposal in which the rate freeze described above would be extended through December 31, 2010. Under the settlement proposal, for calendar years 2006 through 2010, an amount equal to 40% of revenues associated with Iowa retail electric returns on equity between 11.75% and 13.0%; 50% of revenues associated with Iowa retail electric returns on equity between 13.0% and 14.0%; and 83.3% of revenues associated with Iowa retail electric returns on equity greater than 14.0% will be applied as a reduction to offset some of the capital costs on the Iowa portion of three generation projects. If Iowa retail electric returns on equity fall below 10% in any 12-month period after January 1, 2006, MidAmerican Energy has the ability to file for a general increase in rates under the proposed settlement. The proposed settlement is subject to approval by the IUB. The IUB is expected to rule on the proposal during the second half of 2003.

Under an Illinois restructuring law enacted in 1997, as amended in 2002, a sharing mechanism is in place for MidAmerican Energy's Illinois regulated retail electric operations whereby earnings above a computed level of return on common equity will be shared equally between customers and MidAmerican Energy. MidAmerican Energy's computed level of return on common equity is based on a rolling two-year average of the Monthly Treasury Long-Term Average Rate, as published by the Federal Reserve System, plus a premium of 8.5% for 2000 through 2004 and a premium of 12.5% for 2005 and 2006. The two-year average above which sharing must occur for 2002 was 14.03%. The law allows MidAmerican Energy to mitigate the sharing of earnings above the threshold return on common equity through accelerated recovery of regulatory assets.

On March 15, 2002, MidAmerican Energy made a filing with the IUB requesting an increase in retail gas rates. On June 12, 2002, the IUB issued an order granting MidAmerican Energy an interim increase of approximately $13.8 million annually, effective. On July 15, 2002 MidAmerican Energy and the Iowa Office of Consumer Advocate filed a proposed settlement agreement with the IUB. The settlement agreement, which was approved by the IUB on November 8, 2002, provides for an increase in rates of $17.7 million annually for MidAmerican Energy's Iowa retail natural gas customers and freezes such rates for two years after the date the IUB approves tariffs implementing the settlement agreement. MidAmerican Energy implemented the new rates effective November 25, 2002.

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Kern River and Northern Natural Gas

Kern River and Northern Natural Gas are subject to regulation by various federal and state agencies as discussed below.

As owners of interstate natural gas pipelines, Northern Natural Gas' and Kern River's rates, services and operations are subject to regulation by the FERC. The FERC administers, among other things, the Natural Gas Act and the Natural Gas Policy Act of 1978. Additionally, interstate pipeline companies are subject to regulation by the Department of Transportation pursuant to the Natural Gas Pipeline Safety Act, which establishes safety requirements in the design, construction, operations and maintenance of interstate natural gas transmission facilities.

The FERC has jurisdiction over, among other things, the construction and operation of pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. The FERC also has jurisdiction over the rates and charges and terms and conditions of service for the transportation of natural gas in interstate commerce. Its pipeline subsidiaries also are required to file with the FERC an annual report on Form 2, which is publicly available, disclosing general corporate information and financial statements regarding its pipeline subsidiaries.

Kern River's tariff rates were designed to give it an opportunity to recover all actually and prudently incurred operations and maintenance costs of its pipeline system, taxes, interest, depreciation and amortization and a regulated equity return. Kern River's rates are set using a "levelized cost-of-service" methodology so that the rate is constant over the contract period. This is achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expense decreases.

Northern Natural Gas has implemented a straight fixed variable rate design which provides that all fixed costs assignable to firm capacity customers, including a return on equity, are to be recovered through fixed monthly demand or capacity reservation charges which are not a function of throughput volumes.

Northern Natural Gas' current tariff structure provides for:

• seasonality in demand rates;
• extension of the majority of firm storage and transport contracts through May 31, 2003 and October 31, 2003, respectively;
• a rate moratorium through October 31, 2003, with limited re-openers based on the FERC's rulemaking changes; and
• the right of Northern Natural Gas to file for term-differentiated rates, if allowed.

Northern Natural Gas' tariff rates were designed to recover a cost of service that would reflect a 12.3% return on equity based upon the settlement reached in FERC Docket No. RP98-203. On May 1, 2003, Northern Natural Gas filed a request for increased rates with the FERC. The rate filing was made in accordance with the FERC settlement referred to above that required Northern Natural Gas to file a new rate case between May 1, 2003 and April 30, 2004. The rate filing provides evidence in support of a $71 million increase to Northern Natural Gas' annual revenue requirement. However, Northern Natural Gas is requesting that only $55 million of this increase be effectuated. Northern Natural Gas anticipates that the FERC will suspend the rate increase until November 2004 to allow the FERC staff and Northern Natural Gas' customers time to fully review all of the cost and supporting data related to the increase.

In 2000, the FERC issued new rules with respect to terms and conditions of interstate pipeline transportation service pursuant to Order No. 637. In Order No. 637, the FERC made changes to its regulatory model to enhance the effectiveness and efficiency of gas markets as they evolved since the series of FERC orders commonly referred to as Order No. 436, No. 500 and No. 636 which were adopted beginning in the mid-1980s to the early 1990s and which provided for the restructuring of interstate pipeline sales and services. Specifically, in Order No. 637 the FERC:

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• addressed alternatives to traditional pipeline pricing by permitting peak/off-peak and term differentiated rate structures;
• revised certain reporting requirements; and
• made changes in regulations related to (1) scheduling equality for released capacity, (2) capacity segmentations, and (3) pipeline imbalance services, operational flow orders and penalties.

On July 17, 2000, Northern Natural Gas made its initial compliance filing in accordance with Order No. 637. Northern Natural Gas made a revised Order No. 637 compliance filing on March 4, 2002 and a supplemental filing on May 10, 2002. On November 21, 2002, the FERC issued an Order on Compliance with Order Nos. 637, 587-G and 587-L. In the November 21, 2002 Order, the FERC found that Northern Natural Gas generally complied with Order Nos. 637, 587-G and 587-L, subject to certain modifications, and ordered Northern Natural Gas to file compliance tariffs within 30 days. Northern filed in compliance with the November 21, 2002 order on December 21, 2002. At this time, an order on Compliance has not been issued. In addition, numerous parties filed for rehearing of the November 21, 2002 order, which are also pending.

As a result of the FERC's policies favoring competition in gas markets and the expansion of existing pipelines and construction of new pipelines, the interstate pipeline industry has begun to experience some turnback of firm capacity as existing transportation service agreements expire and are terminated. LDCs and end-use customers have more choices in the new, more competitive environment and may be able to shift load from one pipeline to another. If a pipeline experiences capacity turnback and is unable to remarket the capacity, the pipeline or its other customers may have to bear the costs associated with the capacity that is turned back. These issues will be resolved in a pipeline's general rate case proceedings.

The FERC also has authority over gas pipelines' accounting practices. The FERC recently issued a notice of proposed rulemaking regarding gas accounting issues which would limit the ability of gas pipelines to enter into cash management agreements with their parent companies. We are in the process of reviewing such proposed rule, but we do not believe the rule will have a material adverse impact on us and our pipeline subsidiaries.

On August 1, 2002, the FERC issued an Order to respond to Northern Natural Gas related to Northern Natural Gas' existing $450.0 million revolving credit facility and to cash management record keeping by Northern Natural Gas. Pursuant to a Stipulation and Consent Agreement dated August 8, 2002, Northern Natural Gas agreed to comply with the FERC's cash management practices and to not include the costs associated with its existing $450.0 million revolving credit facility in any future rate proceeding.

Additional proposals and proceedings that might affect the interstate pipeline industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. In some states various forms of restructuring legislation have been passed and in many states local utility regulatory agencies are overseeing the restructuring. As a result of restructuring, LDCs could unbundle their services and withdraw from all or part of their merchant function, and electric utilities could divest their generating function. This restructuring would result in the interstate pipelines having different customer profiles, including independent gas marketers and independent power generators and end-users. We cannot predict when or if any new proposals might be implemented or, if so, how Kern River and Northern Natural Gas might be affected.

Other United States Regulation

The Public Utility Regulatory Policies Act of 1978, as amended, or PURPA, and PUHCA are two of the laws (including the regulations thereunder) that affect us and certain of our subsidiaries' operations. PURPA provides to QFs certain exemptions from federal and state laws and regulations, including organizational, rate and financial regulation. PUHCA extensively regulates and restricts the activities of registered public utility holding companies and their subsidiaries. Congress is currently considering major changes to both PUHCA and PURPA. Any such legislation, if adopted, could vary

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considerably from the terms contained in either or both of the House and Senate versions which are presently under consideration. We believe that if the current proposed legislation is passed, it would apply to new projects only and thus, although potentially impacting its ability to develop new domestic projects, it would not affect our existing qualifying facilities. We cannot provide assurance, however, that legislation, if passed, or any other similar legislation proposed in the future, would not adversely impact our existing domestic projects.

We are currently exempt from regulation under all provisions of PUHCA, except the provisions that regulate the acquisition of securities of public utility companies, based on the intrastate exemption in Section 3(a)(1) of PUHCA. In order to maintain this exemption, we and each of our public utility subsidiaries from which we derive a material part of its income (currently only MidAmerican Energy) must be predominantly intrastate in character and organized in and carry on our and MidAmerican Energy's respective utility operations substantially in our state of organization (currently Iowa). Except for MidAmerican Energy's generating plant assets, the majority of our domestic power plants and all of our foreign utility operations are not public utilities within the meaning of PUHCA as a result of their status as QFs under PURPA (with our ownership interest therein limited to 50%), exempt wholesale generators or foreign utility companies, or are otherwise exempted from the definition of "public utility" under PUHCA. If we were to cease to be exempt or if we were to become a subsidiary of a non-exempt holding company, we would become subject to additional regulation by the SEC under PUHCA. Under PUHCA, registered holding companies and their subsidiaries are subject to regulation and restrictions with respect to certain of their activities, including securities issuances, acquisitions, investments and affiliate transactions. There can be no assurances that such regulation would not have a material adverse effect on us.

In the event we were unable to avoid the loss of QF status for one or more of our affiliate's facilities, such an event could result in termination of a given project's power sales agreement and a default under the project subsidiary's project financing agreements, which, in the event of the loss of QF status for one or more facilities, could have a material adverse effect on us.

Regulatory requirements applicable in the future to nuclear generating facilities could adversely affect the results of operations of us and MidAmerican Energy, in particular. We are subject to certain generic risks associated with utility nuclear generation, including risks arising from the operation of nuclear facilities and the storage, handling and disposal of high-level and low-level radioactive materials; risks of a serious nuclear incident; limitations on the amounts and types of insurance commercially available in respect of losses that might arise in connection with nuclear operations; and uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. Revised safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at nuclear plants, including those in which MidAmerican Energy has an ownership interest, such as the Quad Cities units, and additional such expenditures could be required in the future.

CE Electric UK

Since 1990, the electricity generation, supply and distribution industries in Great Britain have been privatized, and competition has been introduced in generation and supply. Electricity is produced by generators, transmitted through the national grid transmission system and distributed to customers by the fourteen Distribution License Holders, or DLHs, in their respective distribution service areas. During the fourth quarter of 1998, the market for supplying electricity began to be opened to competition through a phased-in program. This program, which proceeded by geographic areas, was completed in 1999.

Under the Utilities Act 2000, the public electricity supply license created pursuant to the Electricity Act 1989 was replaced by two separate licenses-the electricity distribution license and the electricity supply license. When the relevant provision of the Utilities Act 2000 became effective on October 1, 2001, the public electricity supply licenses formerly held by Northern Electric and Yorkshire were split so that separate subsidiaries held licenses for electricity distribution and

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electricity supply. In order to comply with the Utilities Act 2000 and to facilitate this license splitting, Northern Electric and Yorkshire (and each of the other holders of the former public electricity supply licenses) each made a statutory transfer scheme that was approved by the Secretary of State for Trade and Industry. These schemes provided for the transfer of certain assets and liabilities to the licensed subsidiaries. This occurred on October 1, 2001, a date set by the Secretary of State for Trade and Industry. As a consequence of these schemes, the electricity distribution businesses of Northern Electric and Yorkshire were transferred to NEDL and YEDL, respectively. NEDL and YEDL are each holders of an electricity distribution license. The residual elements of the Electricity Supply licenses were transferred to Innogy in connection with the sale of Northern Electric's electricity and gas supply business to Innogy and the retention by Innogy of the electricity and gas supply business of Yorkshire, all as a part of the Yorkshire Swap on September 21, 2001.

Each of the DLHs is required to offer terms for connection to its distribution system and for use of its distribution system to any person. In providing the use of its distribution system, a DLH must not discriminate between users, nor may its charges differ except where justified by differences in cost.

Most revenue of the DLHs is controlled by a distribution price control formula which is set out in the license of each DLH. It has been the practice of Ofgem (and its predecessor body, the Office of Electricity Regulation), to review the formula periodically and to reset it at intervals of five year duration. The formula may be varied with the consent of the DLH, or if the DLH does not consent, following a review by the U.K.'s competition authority.

The periodic review during which the formula is reset is the process by which Ofgem determines its view of the future allowed revenue of DLHs. The procedure and methodology adopted at a price control review is at the reasonable discretion of Ofgem. At the last such review, concluded in 1999 and effective April 2000, Ofgem's judgment of the future allowed revenue of licensees was based upon, among other things:

• the actual operating costs of each of the licensees;
• the operating costs which each of the licensees would incur if it were as efficient as, in Ofgem's judgment, the most efficient licensee;
• the regulatory value to be ascribed to each of the licensees' distribution network assets;
• the allowance for depreciation of the distribution network assets of each of the licensees;
• the rate of return to be allowed on investment in the distribution network assets by all licensees; and
• the financial ratios of each of the licensees and the license requirement for each licensee to maintain an investment grade status.

As a result of the most recent review, the allowed revenue of Northern Electric's distribution business was reduced by 24%, in real terms, and the allowed revenue of Yorkshire's distribution business was reduced by 23%, in real terms, with effect from April 1, 2000. The range of reductions for all licensees in Great Britain was between 4% and 33%.

For the duration of the current regulatory period, the 1999 review also requires that regulated distribution revenue per unit be increased or decreased each year by RPI-Xd, where the factor "RPI" is the United Kingdom retail price index reflecting the average of the 12-month inflation rates recorded for each month in the previous July to December period and "Xd" is an adjustment factor which was established by Ofgem at the 1999 review (and continues to be set) at 3%. The formula also takes account of the changes in system electrical losses, the number of customers connected and the voltage at which customers receive the units of electricity distributed. This formula determines the maximum average price per unit of electricity distributed (in pence per kWh) which a DLH is entitled to charge. The distribution price control formula permits DLHs to receive additional revenue due to increased distribution of units and a predetermined increase in customer numbers. Once set, the price control formula does not, during its duration, seek to constrain the profits of a DLH from year to year. It is a control on revenue that operates independently of most of the DLH's costs. During the duration of the price control, additional cost savings or costs, if any, therefore directly impact profit.

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The distribution prices allowable under the current distribution price control formula are expected to be reviewed by Ofgem in time for a revised formula to take effect from April 1, 2005. The formula may be further reviewed at other times in the discretion of the regulator. Ofgem has recently modified the licenses of all DLHs to implement an "Information and Incentives Project" under which up to 2% of a DLH's regulated income depends upon the performance of the DLH's distribution system as measured by the number and duration of customer interruptions and upon the level of customer satisfaction monitored by Ofgem.

Under the Utilities Act 2000, GEMA is able to impose financial penalties on license holders who contravene (or have in the past contravened) any of their license duties or certain of their duties under the Electricity Act 1989 or who are failing (or have in the past failed) to achieve a satisfactory performance in relation to the individual standards of performance prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the licensee's revenue.

CalEnergy Generation – Domestic

Each of the operating domestic power facilities owned through CE Gen meets the requirements promulgated under PURPA to be qualifying facilities. QF status under PURPA provides two primary benefits. First, regulations under PURPA exempt QFs from PUHCA, the FERC rate regulation under the Federal Power Act and the state laws concerning rates of electric utilities and financial and organization regulations of electric utilities. Second, the FERC's regulations promulgated under PURPA require that (1) electric utilities purchase electricity generated by QFs, the construction of which commenced on or after November 9, 1978, at a price based on the purchasing utility's Avoided Cost of Energy, (2) electric utilities sell back-up, interruptible, maintenance and supplemental power to QFs on a non-discriminatory basis, and (3) electric utilities interconnect with QFs in their service territories. There can be no assurance that the QF status of such CalEnergy Generation-Domestic facilities will be maintained.

Cordova Energy and Power Resources

Cordova Energy and Power Resources are exempt from regulation under PUHCA because they are exempt wholesale generators. Power Resources is also a QF. PUHCA provides that an exempt wholesale generator is not considered to be an electric utility company. An exempt wholesale generator is permitted to sell capacity and electricity in the wholesale markets, but not in the retail markets.

If an exempt wholesale generator is subject to a "material change" in facts that might affect its continued eligibility for exempt wholesale generator status, within 60 days of such material change, the exempt wholesale generator must (1) file a written explanation of why the material change does not affect its exempt wholesale generator status, (2) file a new application for exempt wholesale generator status, or (3) notify the FERC that it no longer wishes to maintain exempt wholesale generator status.

CalEnergy Generation – Foreign

In connection with an interagency review of approximately 40 independent power project contracts in the Philippines, the Casecnan Project (together with four other unrelated projects) has reportedly been identified as raising legal and financial questions and, with those projects, has been prioritized for renegotiation. MEHC's subsidiaries' Upper Mahiao, Mahanagdong, and Malitbog projects have also reportedly been identified as raising financial questions. No written report has yet been issued with respect to the interagency review, and the timing and nature of steps, if any that the Philippine Government may take in this regard are not known. Accordingly, it is not known what, if any, impact the government's review will have on the operations of our Philippine Projects. CE Casecnan representatives, together with certain current and former government officials, also have been requested to appear, and have appeared during 2002 and 2003, before a Philippine Senate committee which has raised questions and made allegations with respect to the Casecnan Project's tariff structure and implementation.

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On May 5, 2003, the Philippine Supreme Court issued its ruling in a case involving an unsolicited BOT project for the development, construction and operation of the new Manila International Airport. Various members of Congress and labor unions initiated the action in the Philippine Supreme Court on September 17, 2002 seeking to enjoin the enforcement of the PIATCO Agreement. The PIATCO Consortium is unrelated to CE Casecnan or MEHC. On March 4, 2003, PIATCO separately initiated an ICC arbitration pursuant to the terms of the PIATCO Agreement. The Supreme Court, in its ruling, stated that there were no unresolved factual issues and therefore it had original jurisdiction and concluded that the pendency of the arbitration did not preclude the court from ruling on a case brought by non-parties to the PIATCO Agreement, such as members of the Philippine Congress or non-governmental organizations. In a public speech on November 29, 2002 prior to the December 10, 2002 oral arguments before the Philippine Supreme Court, Philippine President Arroyo stated that she would not honor the PIATCO Agreement because the executive branch's legal department had concluded it was "null and void." In light of that announcement, the project owners stopped work on the project, which is approximately 90% complete and accordingly has not been placed into commercial operation. In its 10 to 3 ruling (with one abstention) issued on May 5, 2003, the Philippine Supreme Court ruled that the PIATCO Agreement was contrary to Philippine law and public policy and was "null and void." CE Casecnan is assessing the impact of the PIATCO ruling on the Casecnan Project.

On April 24, 2003, S&P lowered its rating of CE Casecnan to 'BB' from 'BB+' as a result of S&P's downgrade of the ROP. The downgrade of the ROP by S&P reflected the country's growing debt burden and fiscal rigidity.

On May 8, 2003, Moody's placed the Ba2 senior secured notes rating of CE Casecnan on review for possible downgrade, noting NIA's supplemental counterclaim seeking to have the Project Agreement declared void. Moody's noted that actions by government related agencies and the resulting instability of contractual arrangements was becoming inconsistent with their rating approach that attaches significant benefit to offtake arrangements with those government supported entities.

HomeServices

The Department of Housing and Urban Development and the Federal Home Administration, or FHA, lender guidelines prohibit the collection of a broker-fee from FHA financed buyers where the FHA lender is affiliated with the real estate broker or where there is no buyer-broker agreement. The majority of HomeServices' subsidiaries have been charging a broker fee to their buyers and sellers, except in circumstances where the FHA guidelines prohibit it. Nonetheless, HomeServices is working with the FHA to change the lenders' guidelines to permit collection of these fees.

Pipeline Safety Regulation

Our pipeline operations are subject to regulation by the United States Department of Transportation under the Natural Gas Pipeline Safety Act of 1969, as amended, relating to design, installation, testing, construction, operation and management of its pipeline system. The Natural Gas Pipeline Safety Act requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain inspection and maintenance plans and to comply with such plans. We conduct internal audits of its facilities every four years, with more frequent reviews of those it deems higher risk. The Department of Transportation also routinely audits our pipeline facilities. Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis.

The aging pipeline infrastructure in the United States has led to heightened regulatory and legislative scrutiny of pipeline safety and integrity practices. The Natural Gas Pipeline Safety Act was amended by the Pipeline Safety Act of 1992 to require the Department of Transportation's Office of Pipeline Safety to consider protection of the environment when developing minimum pipeline safety regulations. In addition, the amendments require that the Department of Transportation issue pipeline regulations concerning, among other things, the circumstances under which emergency flow restriction devices should be required, training and qualification standards for personnel involved in maintenance

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and operation, and requirements for periodic integrity inspections, as well as periodic inspection of facilities in navigable waters which could pose a hazard to navigation or public safety. In addition, the amendments narrowed the scope of its gas pipeline exemption pertaining to underground storage tanks under the Resource Conservation and Recovery Act. We believe our pipeline operations comply in all material respects with the Natural Gas Pipeline Safety Act, as amended.

The Pipeline Safety Improvement Act of 2002 requires major new programs in the areas of operator qualification, risk analysis and integrity management. The act requires the periodic inspection or testing of pipelines in areas where the potential consequences of a gas pipeline accident may be significant or may do considerable harm to people and their property, which are referred to as High Consequence Areas.

Environmental Regulation

Domestic

We are subject to a number of federal, state and local environmental and environmentally related laws and regulations affecting many aspects of our present and future operations in the United States. Such laws and regulations generally require us to obtain and comply with a wide variety of licenses, permits and other approvals. We believe that our operating power facilities and gas pipeline operations are currently in material compliance with all applicable federal, state and local laws and regulations. However, no guarantee can be given that in the future we will be 100% compliant with all applicable environmental statutes and regulations or that all necessary permits will be obtained or approved. In addition, the construction of new power facilities and gas pipeline operations is a costly and time-consuming process requiring a multitude of complex environmental permits and approvals prior to the start of construction that may create the risk of expensive delays or material impairment of project value if projects cannot function as planned due to changing regulatory requirements or local opposition. We cannot assure you that existing regulations will not be revised or that new regulations will not be adopted or become applicable to us which could have an adverse impact on our operating costs and operations.

In accordance with the requirements of Section 112 of the Clean Air Act Amendments of 1990, the EPA has performed a study of the hazards to public health reasonably anticipated to occur as a result of emissions of hazardous air pollutants by electric utility steam generating units. In December 2000, after research and monitoring of mercury emissions, the EPA concluded that it is appropriate and necessary to regulate mercury emissions from coal-fired generating units. It is anticipated that rules will be developed to regulate these emissions in 2003 or 2004 with reductions of mercury emissions effective in 2007. The cost to MidAmerican Energy of reducing its mercury emissions would depend on available technology at the time, but could be material.

In July 1997, the EPA adopted revisions to the National Ambient Air Quality Standards for ozone and a new standard for fine particulate matter. Based on data to be obtained from monitors located throughout each state, the EPA will determine which states have areas that do not meet the air quality standards (i.e., areas that are classified as nonattainment). The standards were subjected to legal proceedings, and in February 2001, United States Supreme Court upheld the constitutionality of the standards, though remanding the issue of implementation of the ozone standard to the EPA. As a result of a decision rendered by the United States Circuit Court of Appeals for the District of Columbia, the EPA is moving forward in implementation of the ozone and fine particulate standards and is analyzing existing monitoring data to determine attainment status.

The impact of the new standards on us is currently unknown. MidAmerican Energy's generating stations may be subject to emission reductions if the stations are located in nonattainment areas or contribute to nonattainment areas in other states. As part of state implementation plans to achieve attainment of the standards, MidAmerican Energy could be required to install control equipment on its generating stations or decrease the number of hours during which these stations operate.

The ozone and fine particulate matter standards could also, in whole or in part, be superceded by one of a number of multi-pollutant emission reduction proposals currently under consideration at the

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federal level. In July 2002 and again in 2003, legislation was introduced in Congress to implement the Bush Administration's "Clear Skies Initiative," calling for the reduction in emissions of sulfur dioxide, nitrogen oxides and mercury through a cap-and-trade system. Reductions would begin in 2008 with additional emission reductions being phased in through 2018. While legislative action is necessary for this or other multi-pollutant emission reduction initiatives to become effective, MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions required to meet emissions reductions of this nature.

Since the adoption of the United Nations Framework on Climate Change in 1992, there has been a worldwide effort to reduce greenhouse gas, or GHG, emissions to 1990 levels or below. In December 1997, the U.S. participated in the Kyoto, Japan negotiations, where the basis of a Climate Change treaty was formulated. Under the treaty, known as the Kyoto Protocols, the United States would have an overall reduction target of 7% in GHG emissions from 1990 levels by 2012. To date, the Senate has not ratified the Kyoto Protocol. In addition, President Bush has indicated his opposition to the Kyoto Protocols. However, given the widespread international and public support for the reduction of GHG emissions, the clear possibility exists that GHG reduction regulations will come to pass even if not related to the Kyoto Protocol. At this time, we cannot estimate the potential impact of such regulations on us or our subsidiaries.

In 2001, the state of Iowa passed legislation that, in part, requires rate-regulated utilities to develop a multi-year plan and budget for managing regulated emissions from their generating facilities in a cost-effective manner. MidAmerican Energy's proposed plan and associated budget was filed with the IUB on April 1, 2002, in accordance with state law. MidAmerican Energy expects a final ruling from the IUB regarding such plan during the second quarter of 2003. MidAmerican Energy is required to file updates to such plan at least every two years.

MidAmerican Energy's plan provides its projected air emission reductions considering current proposals being debated at the federal level and describes a coordinated long-range plan to achieve these air emission reductions. MidAmerican Energy's plan also provides specific actions to be taken at each coal-fired generating facility and related costs and timing for each action.

MidAmerican Energy's plan outlines $732.0 million in environmental investments to existing coal-fired generating units, some of which are jointly owned, over a nine-year period from 2002 through 2010. MidAmerican Energy's share of these investments is $546.6 million, $67.9 million of which is projected to be incurred during the current 2002-2005 rate freeze period. Such plan also identifies expenses that will be incurred at the generating facilities to operate and maintain the environmental equipment installed as a result of such plan.

In recent years the EPA has requested, from several utilities, information and support regarding their capital projects for various generating plants. The requests were issued as part of an industry-wide investigation to assess compliance with the New Source Review provision and the New Source Performance Standards of the Clean Air Act. In December 2002, MidAmerican Energy received a request from the EPA to provide documentation related to its capital projects from January 1, 1980 to the present for its Neal, Council Bluffs, Louisa and Riverside Energy centers. MidAmerican Energy has responded to this request. In April 2003, MidAmerican Energy received a second request to which it is preparing a response. At this time MidAmerican Energy cannot predict the outcome of these requests.

Federal, state and local environmental laws and regulations currently have, and future modifications may have, the effect of increasing the lead time for the construction of new facilities, significantly increasing the total cost of new facilities, requiring modification of our existing facilities, increasing the risk of delay on construction projects, increasing our cost of waste disposal and possibly reducing the reliability of service we provide and the amount of energy available from our facilities. Any of such items could have a substantial impact on amounts we are required to expend in the future.

Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to

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investigate and remediate past releases or threatened releases of hazardous or toxic substances or petroleum products located at the facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by a party in connection with any releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict and joint and several. The cost of investigation, remediation or removal of substances may be substantial. In connection with the ownership and operation of facilities, we and our subsidiaries may be liable for such costs. Even at those sites where we are not presently aware of any contamination that currently requires remediation, given the use of hazardous substances at each facility and their locations, often within areas that have a long history of industrial use, it is possible that we will discover currently unknown contamination or that future spills or other causes of contamination will occur. As a result, it is possible that we may become liable for remediation.

The EPA and state environmental agencies have determined that contaminated wastes remaining at certain decommissioned manufactured gas plant facilities may pose a threat to the public health or the environment if such contaminants are in sufficient quantities and at such concentrations as to warrant remedial action.

MidAmerican Energy has evaluated or is evaluating 27 properties that were, at one time, sites of gas manufacturing plants in which MidAmerican Energy may be a potentially responsible party. The purpose of these evaluations is to determine whether waste materials are present, whether the materials constitute an environmental or health risk and whether MidAmerican Energy has any responsibility for remedial action. MidAmerican Energy estimates the range of possible costs for investigation, remediation and monitoring for these sites to be $16 million to $54 million. As of March 31, 2003 and December 31, 2002, MidAmerican Energy had recorded a liability of $21 million and $17 million, respectively, for these sites. MidAmerican Energy's present rates in Iowa provide for a fixed annual recovery of manufactured gas plant costs.

Pursuant to the Toxic Substances Control Act, a federal law administered by the EPA, MidAmerican Energy developed a comprehensive program for the use, handling, control and disposal of all polychlorinated biphenyls, or PCBs, contained in electrical equipment. The future use of equipment containing PCBs will be minimized. Capacitors, transformers and other miscellaneous equipment are being purchased with a non-PCB dielectric fluid. MidAmerican Energy's exposure to PCB liability has been reduced through the orderly replacement of a number of such electrical devices with similar non-PCB electrical devices.

Accruals for probable remediation costs are established based on site-specific estimates and are evaluated and revised quarterly as appropriate based on additional information obtained during investigation and remedial activities. The estimated recorded liability could change materially based on facts and circumstances derived from site investigations, changes in required remedial action and changes in technology relating to remedial alternatives. Insurance recoveries have been received for some of the sites under investigation. Those recoveries are intended to be used principally for accelerated remediation, as specified by the IUB, and are recorded as a regulatory liability. Additionally, as viable potentially responsible parties are identified, those parties are evaluated for potential contributions, and cost recovery is pursued when appropriate.

Although the timing of potential incurred costs and recovery of costs in MidAmerican Energy's rates may affect the results of operations in individual periods, management believes that the outcome of issues related to the remediation of former manufactured gas plant facilities will not have a material adverse effect on its financial position, results of operations or cash flows.

United Kingdom

CE Electric UK's businesses are subject to extensive regulatory requirements with respect to the protection of the environment.

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The United Kingdom government introduced new contaminated land legislation in April 2000 that requires local authorities to put in place a program for investigating land in their area in order to identify contamination.

• Local authorities can serve remediation notices where contamination poses a threat to the greater environment.
• If the "person" who contaminated the land cannot be found, the landowner is responsible.

CE Electric UK is in the process of completing the evaluation work on the three sites that may be subject to the legislation. Exploratory work with an environmental remediation company is in progress on these sites.

The Environmental Protection Act (Disposal of PCB's and other Dangerous Substances) Regulations 2001 were introduced on May 5, 2000. The regulations required that transformers containing over 50 parts per million of PCB's and other dangerous substances be registered with the United Kingdom Environment Agency, or the Environment Agency, by July 31, 2000. Transformers containing 500 parts per million had to be decontaminated by December 31, 2000. CE Electric UK has registered 380 items above 50 parts per million, decontaminated 120 items and informed the Environment Agency that it is continuing with its sampling, labeling and registration program. These regulations are not expected to have a material impact on us.

The 1998 Groundwater Regulations seek to prevent listed hazardous substances from entering groundwater and strengthens the Environment Agency's powers to require additional protective measures, especially in areas of important groundwater supplies. Mineral oils and hydrocarbons are included in the list of more tightly controlled substances, or List I substances. This affects the high voltage fluid filled electricity cable network incorporating an insulating fluid that is currently in List I. The existing voluntary Operating Code of Practice, as agreed between the Environment Agency and the Electricity Supply Industries, is undergoing revision through the services of the Electricity Association to address the regulatory changes. The existing voluntary Operating Code of Practice is, and any revised Operating Code of Practice will be, incorporated into the operating practices of NEDL and YEDL. Any revisions made are not expected to have a material impact on us.

The Oil Storage Regulations became effective in 2002 and require the phased introduction of secondary containment measures (bunding) for all above ground oil storage locations where the capacity is more than 200 liters. The primary containers must be in sound condition, leak free, and positioned away from vehicle traffic routes. The secondary containment must be impermeable to water and oil (without drainage valve) and be subject to routine maintenance. The capacity of the bund must be sufficient to hold up to 110% of the largest stored vessel or 25% of the maximum stored capacity, whichever is the greater. The full impact of the regulations is being phased in over the next three years. On March 1, 2002, these regulations came into effect for all new oil storage facilities. On September 1, 2003, the regulations become effective for existing storage facilities at "significant risk" (i.e. within 10 meters of a water course), and on September 1, 2005 the regulations come into effect for all remaining storage facilities. A detailed study of the impacts has been carried out and a plan of action prepared to ensure compliance. We expect that the cost of compliance with such regulations will not have a material impact on us.

The Electricity Act 1989 obligates either the United Kingdom Secretary of State or the Director General of Electric Supply to take into account the effect of electricity generation, transmission and supply activities on the physical environment when approving applications for the construction of overhead power lines. The Electricity Act requires CE Electric UK to consider the desirability of preserving natural beauty and the conservation of natural and man-made features of particular interest when it formulates proposals for development in connection with certain of its activities. CE Electric UK mitigates the effects its proposals have on natural and man-made features and administers an environmental assessment when it intends to lay cables, construct overhead lines or carry out any other development in connection with its licensed activities. We expect that the cost of compliance with these obligations and the mitigation thereof will not have a material impact on us.

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CE Electric UK's policy is to carry out its activities in such a manner as to minimize the impact of its works and operations on the environment, and in accordance with environmental legislation and good practice. There have not been any significant regulatory environmental compliance issues and there are no material legal or administrative proceedings pending against CE Electric UK with respect to any environmental matter.

Environmental laws and regulations in the United Kingdom currently have, and future modifications may increasingly have, the effect of requiring modification of CE Electric UK's facilities and increasing its operating costs.

Employers in the United Kingdom have an obligation to manage the exposure of their workforce to asbestos, as it can have a detrimental impact on human health. The Control of Asbestos at Work Regulations 2002 came into force in England, Scotland and Wales in two tranches. Most of the regulations came into force on November 21, 2002 and the remainder will come into force on May 21, 2003. These regulations implement a European Directive and will increase the obligations on employers to create a safe working environment. The regulations could also result in expenditure having to be committed to asbestos management plans and, in some cases, to the removal of asbestos. We expect that the cost of compliance with this new regulation will not have a material impact on us.

Philippines

On June 23, 1999, the Philippine Congress enacted the Philippine Clean Air Act of 1999. The related implementing rules and regulations were adopted in November 2000. The law as written would require the Leyte Projects to comply with a maximum discharge of 200 grams of hydrogen sulfide per gross MWh of output by June 2004. On November 13, 2002, the Secretary of the Philippine Department of Environmental and Natural Resources issued a Memorandum Circular, or MC, designating geothermal areas as "special airsheds." PNOC-EDC has advised us that the MC exempts the Mahanagdong and Malitbog plants from the need to comply with the point-source emission standards of the Clean Air Act. The Leyte Projects have sought confirmation of the impact of the MC from PNOC-EDC and from the Philippine Department of Environmental and Natural Resources.

Nuclear Regulation

Under the Nuclear Waste Policy Act of 1982, the United States Department of Energy is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Exelon Generation, as required by the Nuclear Waste Act, signed a contract with the Department of Energy to provide for the disposal of spent nuclear fuel and high-level radioactive waste beginning not later than January 1998. The Department of Energy did not begin receiving spent nuclear fuel on the scheduled date, and it is expected that the schedule will be significantly delayed. The costs incurred by the Department of Energy for disposal activities are being financed by fees charged to owners and generators of the waste. Exelon Generation has informed MidAmerican Energy that existing on-site storage capability at Quad Cities Station is sufficient to permit interim storage into 2005. For Quad Cities Station, Exelon Generation has informed MidAmerican Energy that it plans to develop interim spent fuel storage installation at Quad Cities Station to store additional spent nuclear fuel in dry casks. Exelon Generation expects the bulk of the construction work will be done in 2004.

MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in Quad Cities Station Units 1 and 2. Exelon Generation is the operator of Quad Cities Station and is under contract with MidAmerican Energy to secure and keep in effect all necessary NRC licenses and authorizations.

The NRC regulations control the granting of permits and licenses for the construction and operation of nuclear generating stations and subject such stations to continuing review and regulation. The NRC review and regulatory process covers, among other things, operations, maintenance, and environmental and radiological aspects of such stations. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses.

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Federal regulations provide that any nuclear operating facility may be required to cease operation if the NRC determines there are deficiencies in state, local or utility emergency preparedness plans relating to such facility, and the deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy that an emergency preparedness plan for Quad Cities Station has been approved by the NRC. Exelon Generation has also advised MidAmerican Energy that state and local plans relating to Quad Cities Station have been approved by the Federal Emergency Management Agency.

The NRC also regulates the decommissioning of nuclear power plants including the planning and funding for the eventual decommissioning of the plants. In accordance with these regulations, MidAmerican Energy submits a report to the NRC every two years providing "reasonable assurance" that funds will be available to pay the costs of decommissioning its share of Quad Cities Station.

MidAmerican Energy has established external trusts for the investment of funds collected for nuclear decommissioning associated with Quad Cities Station. Electric tariffs currently in effect include provisions for annualized collection of estimated decommissioning costs at Quad Cities Station. In Iowa, Quad Cities Station decommissioning costs are reflected in base rates. MidAmerican Energy's cost related to decommissioning funding in 2002 was $8.3 million.

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LEGAL PROCEEDINGS

In addition to the proceedings described below, we and our subsidiaries are currently parties to various items of litigation or arbitration, none of which are reasonably expected by us to have a material adverse effect.

Pipeline Litigation

In 1998, the United States Department of Justice informed the then current owners of Kern River and Northern Natural Gas that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against such entities and certain of their subsidiaries including Kern River and Northern Natural Gas. Mr. Grynberg has also filed claims against numerous other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties allegedly not paid to the federal government, treble damages, civil penalties, attorneys' fees and costs. On April 9, 1999, the United States Department of Justice announced that it declined to intervene in any of the Grynberg qui tam cases, including the actions filed against Kern River and Northern Natural Gas in the United States District Court for the District of Colorado. On October 21, 1999, the Panel on Multi-District Litigation transferred the Grynberg qui tam cases, including the ones filed against Kern River and Northern Natural Gas, to the United States District Court for the District of Wyoming for pre-trial purposes. Motions to dismiss the complaint, filed by various defendants including Northern Natural Gas and Williams, which was the former owner of Kern River, were denied on May 18, 2001. On October 9, 2002, the United States District Court for the District of Wyoming dismissed Grynberg's Royalty Valuation Claims. Grynberg has appealed this dismissal to the United States Court of Appeals for the Tenth Circuit. In connection with the purchase of Kern River from Williams in March 2002, Williams agreed to indemnify us against any liability for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. No such indemnification was obtained in connection with the purchase of Northern Natural Gas in August 2002. We believe that the Grynberg cases filed against Kern River and Northern Natural Gas are without merit and Williams, on behalf of Kern River pursuant to its indemnification, and Northern Natural Gas, intend to defend these actions vigorously.

On June 8, 2001, a number of interstate pipeline companies, including Kern River and Northern Natural Gas, were named as defendants in a nationwide class action lawsuit which had been pending in the 26th Judicial District, District Court, Stevens County Kansas, Civil Department against other defendants, generally pipeline and gathering companies, since May 20, 1999. The plaintiffs allege that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs. In November 2001, Kern River and Northern Natural Gas, along with the coordinating defendants, filed a motion to dismiss under Rules 9B and 12B of the Kansas Rules of Civil Procedure. In January 2002, Kern River and most of the coordinating defendants filed a motion to dismiss for lack of personal jurisdiction. The court has yet to rule on these motions. The plaintiffs filed for certification of the plaintiff class on September 16, 2002. On January 13, 2003, oral arguments were heard on coordinating defendants' opposition to class certification. On April 10, 2003, the court entered an order denying the plaintiffs' motion for class certification. It is anticipated that the plaintiffs will appeal this decision. Williams has agreed to indemnify us against any liability associated with Kern River for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. Williams, on behalf of Kern River and other entities, anticipates joining with Northern Natural Gas and other defendants in contesting certification of the plaintiff class. Kern River and Northern Natural Gas believe that this claim is without merit and that Kern River's and Northern Natural Gas' gas measurement techniques have been in accordance with industry standards and its tariff.

Philippines

Casecnan Construction Contract.    The Casecnan Project was initially constructed pursuant to the Hanbo Contract on a joint and several basis by Hanbo and HECC. On May 7, 1997, CE Casecnan

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terminated the Hanbo Contract due to defaults by Hanbo and HECC including the insolvency of both companies. On the same date, CE Casecnan entered into a new fixed-price, date certain, turnkey engineering, procurement and construction contract to complete the construction of the Replacement Contract. The work under the Replacement Contract was conducted by a consortium consisting of the Contractor, working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd.

On November 20, 1999, the Replacement Contract was amended to extend the Guaranteed Substantial Completion Date for the Casecnan Project to March 31, 2001. This amendment was approved by the lenders' independent engineer under the Trust Indenture.

On February 12, 2001, the Contractor filed a Request for Arbitration with the ICC seeking schedule relief of up to 153 days through August 31, 2001 resulting from various alleged force majeure events. In its March 20, 2001 Supplement to Request for Arbitration, the Contractor also seeks compensation for alleged additional costs of approximately $4 million it incurred from the claimed force majeure events to the extent it is unable to recover from its insurer. On April 20, 2001, the Contractor filed a further supplement seeking an additional compensation for damages of approximately $62 million for the alleged force majeure event (and geologic conditions) related to the collapse of the surge shaft. The Contractor has alleged that the circumstances surrounding the placing of the Casecnan Project into commercial operation in December 2001 amounted to a repudiation of the Replacement Contract and has filed a claim for unspecified quantum meruit damages, and has further alleged that the delay liquidated damages clause which provides for payments of $125,000 per day for each day of delay in completion of the Casecnan Project for which the Contractor is responsible is unenforceable. The arbitration is being conducted applying New York law and pursuant to the rules of the ICC.

Hearings have been held in connection with this arbitration in July 2001, September 2001, January 2002, March 2002, November 2002 and January 2003. As part of those hearings, on June 25, 2001, the arbitration tribunal temporarily enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di Roma in support of the Contractor's obligations to CE Casecnan for delay liquidated damages. As a result of the continuing nature of that injunction, on April 26, 2002, CE Casecnan and the Contractor mutually agreed that no demands would be made on the Banca di Roma demand guaranty except pursuant to an arbitration award. As of March 31, 2003, however, CE Casecnan has received approximately $6.0 million of liquidated damages from demands made on the demand guarantees posted by Commerzbank on behalf of the Contractor. On November 7, 2002, the ICC issued the arbitration tribunal's partial award with respect to the Contractor's force majeure and geologic conditions claims. The arbitration panel awarded the Contractor 18 days of schedule relief in the aggregate for all of the force majeure events and awarded the Contractor $3.8 million with respect to the cost of the collapsed surge shaft. The $3.8 million is shown as part of the accounts payable and accrued expenses balance at March 31, 2003 and December 31, 2002. All of the Contractor's other claims with respect to force majeure and geologic conditions were denied.

Further hearings on the Contractor's repudiation and quantum meruit claims, the alleged unenforceability of the delay liquidated damages clause and certain other matters had been scheduled for March 24 through March 28, 2003, but were postponed as a result of the commencement of military action in Iraq. The hearings have been rescheduled for June 30 through July 11, 2003.

If the Contractor were to prevail on its claim that the delay liquidated damages clause is unenforceable, CE Casecnan would not be entitled to collect such delay damages for the period from March 31, 2001 through December 11, 2001. If the Contractor were to prevail in its repudiation claim and prove quantum meruit damages in excess of amounts paid to the Contractor, CE Casecnan could be liable to make additional payments to the Contractor. CE Casecnan believes all of such allegations and claims are without merit and is vigorously contesting the Contractor's claims.

Casecnan NIA Arbitration.    Under the terms of the Project Agreement, NIA has the option of timely reimbursing CE Casecnan directly for certain taxes CE Casecnan has paid. If NIA does not so reimburse CE Casecnan, the taxes paid by CE Casecnan result in an increase in the water delivery fee. The payment of certain other taxes by CE Casecnan results automatically in an increase in the

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water delivery fee. As of March 31, 2003, CE Casecnan has paid approximately $58.1 million in taxes, which as a result of the foregoing provisions results in an increase in the Water Delivery Fee. NIA has failed to pay the portion of the water delivery fee each month, related to the payment of these taxes by CE Casecnan. As a result of this non-payment, on August 19, 2002, CE Casecnan filed a Request for Arbitration against NIA, seeking payment of such portion of the water delivery fee and enforcement of the relevant provision of the Project Agreement going forward. The arbitration will be conducted in accordance with the rules of the ICC.

NIA filed its Answer and Counterclaim on March 31, 2003. In its Answer, NIA asserts, among other things, that most of the taxes which CE Casecnan has factored into the water delivery fee compensation formula do not fall within the scope of the relevant section of the Project Agreement, that the compensation mechanism itself is invalid and unenforceable under Philippine law and that the Project Agreement is inconsistent with the Philippine BOT law. As such, NIA seeks dismissal of CE Casecnan's claims and a declaration from the arbitral tribunal that the taxes which have been taken into account in the water delivery fee compensation mechanism are not recoverable thereunder and that, at most, certain taxes may be directly reimbursed (rather than compensated for through the water delivery fee) by NIA. NIA also counterclaims for approximately $7 million which it alleges is due to it as a result of the delayed completion of the Casecnan Project. On April 23, 2003, NIA filed a Supplemental Counterclaim in which it asserts that the Project Agreement is contrary to Philippine law and public policy and by way of relief seeks a declaration that the Project Agreement is void from the beginning or should be cancelled, or alternatively, an order for reformation of the Project Agreement or any portions or sections thereof which may be determined to be contrary to such law and or public policy. On May 23, 2003 CE Casecnan filed its reply to NIA's counterclaims. CE Casecnan intends to vigorously contest all of NIA's assertions and counterclaims.

The three member arbitration panel has been confirmed by the ICC and an initial organizational hearing was held on April 28, 2003. Hearings on this matter are scheduled for July 2004.

Included in revenue, for the three months ended March 31, 2003 and 2002, were $5.5 million and $5.8 million, respectively, of tax compensation for water delivery fees under the Project Agreement, none of which has been paid. As of March 31, 2003 and December 31, 2002, the net receivable for the tax compensation piece of the water delivery fees invoiced since the start of commercial operations totaled $29.8 million and $24.3 million, respectively.

Casecnan Stockholder Litigation.    Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro forma financial projections of the Casecnan Project prepared following commencement of commercial operations, in February 2002, we, through our indirect wholly owned subsidiary CE Casecnan, advised the minority stockholder, LPG, that our indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against, among others, CE Casecnan and us. In the complaint, LPG seeks compensatory and punitive damages for alleged breaches of the stockholder agreement and alleged breaches of fiduciary duties allegedly owed by CE Casecnan Ltd. and us to LPG. The complaint also seeks injunctive relief against all defendants and a declaratory judgment that LPG is entitled to maintain its 15% interest in CE Casecnan. The impact, if any, of this litigation on CE Casecnan cannot be determined at this time.

In February 2003, San Lorenzo, an original shareholder substantially all of whose shares in CE Casecnan we purchased in 1998, threatened to initiate legal action in the Philippines in connection with certain aspects of its option to repurchase such shares on or prior to commercial operation of the Casecnan Project. CE Casecnan believes that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, will vigorously defend any such action.

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MANAGEMENT

Our management structure is organized functionally and our current executive officers and directors and their positions are as follows:


Name Position
David L. Sokol Chairman of the Board, Chief Executive Officer and Director
Gregory E. Abel President, Chief Operating Officer and Director
Patrick J. Goodman Senior Vice President and Chief Financial Officer
Douglas L. Anderson Senior Vice President, General Counsel and Corporate Secretary
Keith D. Hartje Senior Vice President and Chief Administrative Officer
Warren E. Buffett Director
Walter Scott Jr. Director
Marc D. Hamburg Director
W. David Scott Director
Edgar D. Aronson Director
John K. Boyer Director
Stanley J. Bright Director
Richard R. Jaros Director

Officers are elected annually by the Board of Directors. There are no family relationships among the executive officers, nor any arrangements or understanding between any officer and any other person pursuant to which the officer was selected.

Set forth below is certain information with respect to each of the foregoing officers:

DAVID L. SOKOL, 46, Chairman of the Board of Directors and Chief Executive Officer. Mr. Sokol has been CEO since April 19, 1993 and served as our President from April 19, 1993 until January 21, 1995. Mr. Sokol has been Chairman of the Board of Directors since May 1994 and a director since March 1991. Formerly, among other positions held in the independent power industry, Mr. Sokol served as President and Chief Executive Officer of Kiewit Energy Company, which at that time was a wholly owned subsidiary of Peter Kiewit & Sons Inc., and Ogden Projects, Inc.

GREGORY E. ABEL, 40, President, Chief Operating Officer and Director. Mr. Abel joined us in 1992 and initially served as Vice President and Controller. Mr. Abel is a Chartered Accountant and from 1984 to 1992 he was employed by Price Waterhouse. As a Manager in the San Francisco office of Price Waterhouse, he was responsible for clients in the energy industry.

PATRICK J. GOODMAN, 36, Senior Vice President and Chief Financial Officer. Mr. Goodman joined us in 1995, and served in various accounting positions including Senior Vice President and Chief Accounting Officer. Prior to joining us, Mr. Goodman was a financial manager for National Indemnity Company and a senior associate at Coopers & Lybrand.

DOUGLAS L. ANDERSON, 45, Senior Vice President and General Counsel. Mr. Anderson joined us in February 1993 and has served in various legal positions including General Counsel of our independent power affiliates. From 1990 to 1993 Mr. Anderson was a corporate attorney with Fraser, Stryker in Omaha, NE. Prior to that Mr. Anderson was a principal in the firm Anderson and Anderson.

KEITH D. HARTJE, 53, Senior Vice President and Chief Administrative Officer. Mr. Hartje has been with MidAmerican Energy and its predecessor companies since 1973. In that time, he has held a number of positions, including General Counsel and Corporate Secretary, District Vice President for southwest Iowa operations, and Vice President, Corporate Communications.

WARREN E. BUFFETT, 72, Director. Mr. Buffett has been a director of ours since March 2000. He is Chairman of the Board and Chief Executive Office of Berkshire Hathaway. Mr. Buffett is a Director of the Coca-Cola Company, the Gillette Company and The Washington Post Company.

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WALTER SCOTT, JR., 71, Director. Mr. Scott has been a director of ours since June 1991. Mr. Scott was our Chairman and Chief Executive Officer from January 8, 1992 until April 19, 1993. For more than the past five years, he has been Chairman of the Board of Directors of Level 3 Communications, Inc., a successor to certain businesses of Peter Kiewit & Sons Inc. Mr. Scott is a director of Peter Kiewit & Sons Inc., Berkshire Hathaway, Burlington Resources, Inc., ConAgra, Inc., Valmont Industries, Inc., Kiewit Materials Co., Commonwealth Telephone Enterprises, Inc. and RCN Corporation.

MARC D. HAMBURG, 53, Director. Mr. Hamburg has been a director of ours since March 2000. He has served as Vice President – Chief Financial Officer of Berkshire Hathaway since October 1, 1992 and Treasurer since June 1, 1987, his date of employment with Berkshire Hathaway.

W. DAVID SCOTT, 41, Director. Mr. Scott has been a director of ours since March 2000. Mr. Scott formed Magnum Resources, Inc., a commercial real estate investment and management company, in October 1994 and has served as its President and Chief Executive Officer since its inception. Before forming Magnum Resources, Mr. Scott worked for America First Companies, Cornerstone Banking Group and Peter Kiewit & Sons Inc. Mr. Scott has been a director of America First Mortgage Investments, Inc., a mortgage REIT, since 1998.

EDGAR D. ARONSON, 68, Director. Mr. Aronson has been a director of ours since 1983. Mr. Aronson founded EDACO, Inc., a private venture capital company, in 1981, and has been President of EDACO, Inc. since that time. Prior to that, Mr. Aronson was Chairman of Dillon, Read International from 1979 to 1981 and a General Partner in charge of the International Department of Salomon Brothers Inc. from 1973 to 1979. Mr. Aronson served during 1962-1968 as Vice President consecutively in the International Departments of First National Bank of Chicago and Republic National Bank of New York. He founded the International Department of Salomon Brothers and Hutzler in 1968.

JOHN K. BOYER, 59, Director. Mr. Boyer has been a director of ours since March 2000. He is a partner with Fraser, Stryker, Meusey, Olson, Boyer & Bloch, P.C. from 1973 to present with emphasis on corporate, commercial, federal, state, and local taxation.

STANLEY J. BRIGHT, 63, Director. Mr. Bright was Chairman and Chief Executive Officer of MidAmerican Energy from July 1, 1995 until March 1999. Mr. Bright joined Iowa-Illinois Gas and Electric Company (a predecessor of MidAmerican Energy) as Vice President and Chief Financial Officer in 1986, became a director in 1987, President and Chief Operating Officer in 1990, and Chairman and Chief Executive Officer in 1991.

RICHARD R. JAROS, 51, Director. Mr. Jaros has been a director of ours since March 1991. Mr. Jaros served as our President and Chief Operating Officer from January 8, 1992 to April 19, 1993 and as Chairman of the Board from April 19, 1993 to May 1994. Until July 1997, Mr. Jaros was Executive Vice President and Chief Financial Officer of Peter Kiewit & Sons Inc. and President of Kiewit Diversified Group, Inc., which is now Level 3 Communications, Inc. Mr. Jaros serves as director of Commonwealth Telephone Enterprises, Inc., RCN Corporation and Level 3 Communications, Inc.

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Executive Compensation.

The following table sets forth the compensation of our Chief Executive Officer and our four other most highly compensated executive officers who were employed as of December 31, 2002, which we refer to as our Named Executive Officers. Information is provided regarding our Named Executive Officers for the last three fiscal years during which they were our executive officers, if applicable.


Name and Principal Positions Year
Ended
Dec. 31,		 Salary(1) Bonus(1) Other Annual
Comp		 Restricted
Stock
Awards		 Securities
Underlying
Options		 LTIP
Payouts		 All Other
Comp(2)
David L. Sokol   2002   $ 800,000   $ 2,750,000   $ 27,122,550 (3)  $     —   $ —   $     —   $ 7,960  
Chairman and   2001     750,000     2,400,000     —     —     —     —     33,033  
Chief Executive Officer   2000     750,000     4,250,000     —     —     2,199,277     —     40,430  
Gregory E. Abel   2002     540,000     2,200,000     —     —     —     —     7,636  
President and   2001     520,000     1,150,000     —     —     —     —     23,657  
Chief Operating Officer   2000     500,000     1,100,000     —     —     649,052     —     27,530  
Patrick J. Goodman   2002     248,000     365,000     209,560 (4)    —     —     —     7,353  
Senior Vice President and   2001     240,000     260,000     —     —     —     —     13,527  
Chief Financial Officer   2000     230,000     1,183,071     —     —     —     —     14,891  
Douglas L. Anderson   2002     200,000     325,000     —     —     —     —     7,150  
Senior Vice President and   2001     154,427     200,000     —     —     —     —     6,630  
General Counsel   2000     120,000     591,806     —     —     —     —     6,630  
Keith D. Hartje   2002     180,000     65,000     —     —     —     —     7,796  
Senior Vice President and   2001     180,000     60,000     —     —     —     —     6,630  
Chief Administrative Officer   2000     178,173     138,647     —     —     —     —     6,630  
(1) Includes amounts voluntarily deferred by the executive, if applicable.
(2) Consists of 401(k) Plan contributions for 2002 for Mr. Sokol of $7,150, Mr. Abel of $7,150, Mr. Goodman of $7,150, Mr. Anderson of $7,150 and Mr. Hartje of $7,796. To offset its obligations under our Executive Split Dollar Plan for executives whose retirement benefit cannot be fully funded through our Base Retirement Plan for Salaried Employees, we have agreed to pay the premiums for policies of split dollar life insurance on the lives of such executives. No premiums were paid in 2002 for Mr. Sokol, Mr. Abel, or Mr. Goodman. Included are the insurance premiums in the following amounts paid by us with respect to the term life insurance portion of premiums paid in 2002 for Mr. Sokol of $810, for Mr. Abel of $486 and for Mr. Goodman of $203.
(3) Cash amount paid to Mr. Sokol in connection with our purchase of options to purchase our common stock held by Mr. Sokol. The amount paid is equal to the difference between the option exercise prices and the agreed upon value per share.
(4) Cash amount paid to Mr. Goodman in connection with a subsidiary's purchase of options to purchase the subsidiary's common stock held by Mr. Goodman. The amount paid is equal to the difference between the option exercise prices and the agreed upon value per share.

Option Grants in Last Fiscal Year

We did not grant any options during 2002.

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Aggregated Option Exercises In Last Fiscal Year And Fiscal Year End Option Values

The following table sets forth the option exercises and the number of securities underlying exercisable and unexercisable options held by each of our Named Executive Officers at December 31, 2002.


      Underlying Unexercised
Options Held (#)		 Value of Unexercised
In-the-Money Options ($)(1)
Name Shares Acquired
on Exercise (#)		 Value
Realized $		 Exerciseable Unexerciseable Exerciseable Unexerciseable
David L. Sokol   —     —     1,353,504     45,773     N/A     N/A  
Gregory E. Abel   —     —     636,214     12,838     N/A     N/A  
Patrick J. Goodman   —     —     —     —     —     —  
Douglas L. Anderson   —     —     —     —     —     —  
Keith D. Hartje   —     —     —     —     —     —  
(1) On March 14, 2000 we were acquired by a private investor group. As a privately held company, we have no publicly traded equity securities and, consequently, its management does not believe there is a reliable method of computing the present value of the stock options granted to Mr. Sokol and Mr. Abel as shown on the foregoing table.

Long-Term Incentive Plans — Awards in Last Fiscal Year


Name Number of Shares,
Units or Other
Rights (#) (1)		 Performance or Other
Period Until Maturation
or Payout		 Threshold ($) Target ($)(2) Maximum
(#)
Patrick J. Goodman   N/A   December 31, 2006   372,000     N/A     372,000  
Douglas L. Anderson   N/A   December 31, 2006   300,000     N/A     300,000  
Keith D. Hartje   N/A   December 31, 2006   270,000     N/A     270,000  
(1) The awards shown in the foregoing table are made pursuant to the Long-Term Incentive Partnership Plan, or LTIP, which provides that awards vest equally over five years with any unvested balances forfeited upon termination of employment unless the participant retires at or above age 55 with at least 5 years of service in which case the participant will receive any unvested portion of the award. Vested balances are paid to the participant at the time of termination. Once an award is fully vested, the participant may elect to defer or receive payment of part or all of the award. Mr. Sokol and Mr. Abel are not participants in the LTIP. Awards are credited or reduced with annual interest or loss based on a composite of funds or indices.
(2) "Target" and "Threshold" payouts are equivalent with the LTIP.

Compensation of Directors

All directors, excluding Mr. Sokol, Mr. Abel, Mr. Warren Buffett and Mr. Walter Scott, are paid an annual retainer fee of $20,000 and a fee of $500 per day for attendance at Board and Committee meetings. Directors who are employees are not entitled to receive such fees. All directors are reimbursed for their expenses incurred in attending Board meetings.

Retirement Plans

We maintain a Supplemental Retirement Plan for Designated Officers, which we refer to as the Supplemental Plan, to provide additional retirement benefits to designated participants, as determined by the Board of Directors. Mr. Sokol, Mr. Abel, Mr. Goodman and Mr. Hartje are participants in the Supplemental Plan. The Supplemental Plan provides annual retirement benefits up to sixty-five percent of a participant's Total Cash Compensation in effect immediately prior to retirement, subject to a $1 million maximum retirement benefit. "Total Cash Compensation" means the highest amount

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payable to a participant as monthly base salary during the five years immediately prior to retirement multiplied by 12 plus the average of the participant's last three years awards under an annual incentive bonus program and special, additional or non-recurring bonus awards, if any, that are required to be included in Total Cash Compensation pursuant to a participant's employment agreement or approved for inclusion by the Board. Participants must be credited with five years service in order to be eligible to receive benefits under the Supplemental Plan. Each of our Named Executive Officers has or will have five years of credited service with us as of their respective normal retirement age and will be eligible to receive benefits under the Supplemental Plan. A participant who elects early retirement is entitled to reduced benefits under the Supplemental Plan, however, in accordance with their respective employment agreements, Mr. Sokol and Mr. Abel are eligible to receive the maximum retirement benefit at age 47. A survivor benefit is payable to a surviving spouse under the Supplemental Plan. Benefits from the Supplemental Plan will be paid out of general corporate funds; however, through a rabbi trust, we maintain life insurance on the participants in amounts expected to be sufficient to fund the after-tax cost of the projected benefits. Deferred compensation is considered part of the salary covered by the Supplemental Plan.

The supplemental retirement benefit will be reduced by the amount of the participant's regular retirement benefit under the MidAmerican Energy Cash Balance Retirement Plan, which we refer to as the MidAmerican Retirement Plan, that became effective January 1, 1997 and by benefits under the Iowa Resources Inc. and Subsidiaries Supplemental Retirement Income Plan, or IOR Supplemental Plan, as applicable.

The MidAmerican Retirement Plan replaced retirement plans of predecessor companies that were structured as traditional, defined benefit plans. Under the MidAmerican Retirement Plan, each participant has an account, for record keeping purposes only, to which credits are allocated each payroll period based upon a percentage of the participant's salary paid in the current pay period. In addition, all balances in the accounts of participants earn a fixed rate of interest that is credited annually. The interest rate for a particular year is based on the constant maturity Treasury yield plus seven-tenths of one percentage point. At retirement or other termination of employment, an amount equal to the vested balance then credited to the account is payable to the participant in the form of a lump sum or a form of annuity for the entire benefit under the MidAmerican Retirement Plan.

Part A of the IOR Supplemental Plan provides retirement benefits up to sixty-five percent of a participant's highest annual salary during the five years prior to retirement reduced by the participant's MidAmerican Retirement Plan benefit. The percentage applied is based on years of accredited service. A participant who elects early retirement is entitled to reduced benefits under the plan. A survivor benefit is payable to a surviving spouse. Benefits are adjusted annually for inflation. Part B of the IOR Supplemental Plan provides that an additional one hundred-fifty percent of annual salary is to be paid out to participants at the rate of ten percent per year over fifteen years, except in the event of a participant's death, in which event the unpaid balance would be paid to the participant's beneficiary or estate. Deferred compensation is considered part of the salary covered by the IOR Supplemental Plan.

The table below shows the estimated aggregate annual benefits payable under the Supplemental Plan and the MidAmerican Retirement Plan. The amounts exclude Social Security and are based on a straight life annuity and retirement at ages 55, 60 and 65. Federal law limits the amount of benefits payable to an individual through the tax qualified defined benefit and contribution plans, and benefits exceeding such limitation are payable under the Supplemental Plan.

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Total Cash
Compensation
at Retirement ($)		 Estimated Annual Benefit
Age at Retirement
55 60 65
$ 400,000 $ 220,000   $ 240,000   $ 260,000  
   500,000   275,000     300,000     325,000  
   600,000   330,000     360,000     390,000  
   700,000   385,000     420,000     455,000  
   800,000   440,000     480,000     520,000  
   900,000   495,000     540,000     585,000  
1,000,000   550,000     600,000     650,000  
1,250,000   687,500     750,000     812,500  
1,500,000   825,000     900,000     975,000  
1,750,000   962,500     1,000,000     1,000,000  
2,000,000 and greater   1,000,000     1,000,000     1,000,000  

Employment Agreements

Pursuant to his employment agreement Mr. Sokol serves as Chairman of its Board of Directors and Chief Executive Officer. The employment agreement provides that Mr. Sokol is to receive an annual base salary of not less than $750,000, senior executive employee benefits and annual bonus awards that shall not be less than $675,000. Subject to an annual renewal provision, such agreement is scheduled to expire on August 21, 2003.

The employment agreement provides that we may terminate the employment of Mr. Sokol with cause, in which case we are to pay to him any accrued but unpaid salary and a bonus of not less than the minimum annual bonus, or due to death, permanent disability or other than for cause, including a change in control, in which case Mr. Sokol is entitled to receive an amount equal to three times the sum of his annual salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years, as well as three years of accelerated option vesting plus continuation of his senior executive employee benefits (or the economic equivalent thereof) for three years. If Mr. Sokol resigns, we are to pay to him any accrued but unpaid salary and a bonus of not less than the annual minimum bonus, unless he resigns for good reason in which case he will receive the same benefits as if he were terminated other than for cause.

In the event Mr. Sokol has relinquished his position as Chief Executive Officer and is subsequently terminated as Chairman of the Board due to death, disability or other than for cause, he is entitled to any accrued but unpaid salary plus an amount equal to the aggregate annual salary that would have been paid to him through the fifth anniversary of the date he commenced his employment solely as Chairman of the Board, the immediate vesting of all of his options and the continuation of his senior executive employee benefits (or the economic equivalent thereof) through this fifth anniversary. If Mr. Sokol relinquishes his position as Chief Executive Officer but offers to remain employed as the Chairman of the Board, he is to receive a special achievement bonus equal to two times the sum of his annual salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years, as well as two years of accelerated option vesting.

Under the terms of separate employment agreements between us and each of Mr. Abel and Mr. Goodman, each of such executives is entitled to receive two years base salary continuation, payments in respect of average bonuses for the prior two years and two years continued option vesting in the event we terminate his employment other than for cause. If such persons were terminated without cause, Mr. Sokol, Mr. Abel and Mr. Goodman would currently be entitled to be paid approximately $10,125,000, $4,750,000 and $1,175,000, respectively, without giving effect to any tax related provisions.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth certain information regarding beneficial ownership of the shares of our common stock and certain information with respect to the beneficial ownership of each director, our Named Executive Officers and all directors and executive officers as a group as of December 31, 2002.

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Name and Address of Beneficial Owner(1) Number of Shares
Beneficially Owned(2)		 Percentage of
Class(2)
Common Stock:
Walter Scott, Jr. (3)   5,000,000     53.87 % 
David L. Sokol (4)   1,708,224     15.10 % 
Berkshire Hathaway Inc. (5)   900,942     9.71 % 
Gregory E. Abel (6)   700,713     6.20 % 
W. David Scott (7)   624,350     6.73 % 
Douglas L. Anderson   —     —  
Edgar D. Aronson   —     —  
Stanley J. Bright   —     —  
John K. Boyer   —     —  
Warren E. Buffett (8)   —     —  
Patrick J. Goodman   —     —  
Marc D. Hamburg (8)   —     —  
Richard R. Jaros   —     —  
Keith D. Hartje   —     —  
All directors and executive officers
as a group (14 persons)		   8,934,229     78.99 % 
 
(1) Unless otherwise indicated, each address is c/o MidAmerican Energy Holdings Company at 666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309.
(2) Includes shares which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days.
(3) Excludes 3 million shares held by family members and family controlled trusts and corporations, the Scott Family Interests, as to which Mr. Scott disclaims beneficial ownership. Such beneficial owner's address is 1000 Kiewit Plaza, Omaha, Nebraska 68131.
(4) Includes options to purchase 1,384,019 shares of common stock that are exercisable within 60 days.
(5) Such beneficial owner's address is 1440 Kiewit Plaza, Omaha, Nebraska 68131.
(6) Includes options to purchase 644,773 shares of common stock which are exercisable within 60 days.
(7) Includes shares held by trusts for the benefit of or controlled by W. David Scott. Such beneficial owner's address is 11422 Miracle Hills Drive, Suite 400, Omaha, Nebraska 68154.
(8) Excludes 900,942 shares of common stock held by Berkshire Hathaway, of which beneficial ownership is disclaimed.

The terms of our Zero Coupon Convertible Preferred Stock held by Berkshire Hathaway entitle the holder thereof to elect two members of our Board of Directors. The Zero Coupon Convertible Preferred Stock does not vote as to the election of any other members of our Board of Directors. Mr. Sokol's employment agreement gives him the right during the term of his employment to serve as a member of our Board of Directors and to designate two additional directors.

Pursuant to a shareholders agreement, following March 14, 2003, Walter Scott, Jr. or any of the Scott Family Interests would be able to require Berkshire Hathaway to purchase, for an agreed value or an appraised value, any or all of Walter Scott, Jr.'s and the Scott Family Interests' shares of our common stock, provided that Berkshire Hathaway is then a purchaser of a type which is able to consummate such a purchase without causing our or any of our affiliates or us or any of its subsidiaries to become subject to regulation as a registered holding company or a subsidiary of a

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registered holding company under PUHCA. Berkshire Hathaway is not currently such a purchaser. The consummation of such a transaction could result in a change in control with respect to us.

Our Amended and Restated Articles of Incorporation provide that each share of the Zero Coupon Convertible Preferred Stock is convertible at the option of the holder thereof into one conversion unit, which is one share of our common stock subject to certain adjustments as described in its articles, upon the occurrence of a Conversion Event. A "Conversion Event" includes (1) any conversion of Zero Coupon Convertible Preferred Stock that would not cause the holder of the shares of common stock issued upon conversion (or any affiliate of such holder) or us to become subject to regulation as a registered holding company or as a subsidiary of a registered holding company under PUHCA either as a result of the repeal or amendment of PUHCA, the number of shares involved or the identity of the holder of such shares and (2) a Company Sale. A "Company Sale" includes our involuntary or voluntary liquidation, dissolution, recapitalization, winding-up or termination and any merger, consolidation or sale of all or substantially all of its assets. The conversion by Berkshire Hathaway of its shares of Zero Coupon Convertible Preferred Stock into our common stock could result in a change in control with respect to beneficial ownership of its voting securities as calculated pursuant to Rule 13d-3(d) under the Securities Exchange Act.

Certain Relationships and Related Transactions

Under a subscription agreement with us, Berkshire Hathaway has agreed to purchase, under certain circumstances, additional 11% trust issued mandatorily redeemable preferred securities in the event preferred securities outstanding prior to the closing of our acquisition by a private investor group on March 14, 2000 are tendered for conversion to cash by the current holders.

We provided a guarantee in favor of a third party lender in connection with a $1,663,998.75 loan from such lender to our President, Gregory E. Abel, in March of 2000. The loan matures on April 1, 2010. The proceeds of this loan were used by Mr. Abel to purchase 47,475 shares of our common stock. Such common stock (together with 8,465 additional shares of common stock owned by Mr. Abel) also secures the loan. The entire original principal amount of the loan and the guarantee remain presently outstanding.

In order to finance our $275 million preferred stock investment in Williams, on March 7, 2002, we sold to Berkshire Hathaway shares of our Zero Coupon Convertible Preferred Stock. In order to finance our acquisition of Kern River, on March 12, 2002, we sold to Berkshire Hathaway and/or its consolidated subsidiaries shares of our no par, Zero Coupon Convertible Preferred Stock for $127 million and $323 million of 11% mandatorily redeemable preferred securities of our subsidiary trust due March 12, 2012 with scheduled principal payments beginning in 2005. In order to finance our acquisition of Northern Natural Gas, on August 16, 2002, we sold to Berkshire Hathaway and/or its consolidated subsidiaries $950.0 million of 11% mandatorily redeemable preferred securities of its subsidiary trust due August 31, 2012 with scheduled principal payments beginning in 2003. Mr. Warren E. Buffett and Mr. Walter Scott, Jr. are members of the Board of Directors of Berkshire Hathaway. Mr. Buffett and Mr. Marc D. Hamburg are executive officers of Berkshire Hathaway. Each of Mr. Buffett, Mr. Hamburg and Mr. Walter Scott serves on its Board of Directors and participates in deliberations regarding executive officer compensation.

On March 6, 2002, we purchased options to purchase shares of our common stock from Mr. David L. Sokol, our Chairman and Chief Executive Officer. The options purchased had exercise prices ranging from $18.50 to $29.01. We paid Mr. Sokol an aggregate amount of $27,122,550, which is equal to the difference between his option exercise prices and an agreed upon per share value. Mr. Sokol serves on our Board of Directors and participates in deliberations regarding executive officer compensation.

In July 2002, we purchased 557,686 options to purchase shares of HomeServices common stock from directors, officers and employees of HomeServices. The options purchased had exercise prices ranging from $11.3125 to $15.00. We paid an aggregate of $4,268,392, which is equal to the difference between the option exercise prices and an agreed upon per share value.

We have not purchased any other options or securities from our stockholders, directors or executive officers since January 1, 2002.

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Compensation Committee Interlocks and Insider Participation

There is no compensation committee of the Board of Directors. All members of the Board of Directors participate in deliberations regarding executive officer compensation. Mr. Sokol and Mr. Abel are current officers and employees. Mr. Walter Scott is a former officer. Mr. Jaros is a former officer and employee. See "Certain Relationships and Related Transactions."

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DESCRIPTION OF THE NOTES

The original series C notes were, and the series C exchange notes will be, issued pursuant to the supplemental indenture, dated as of May 16, 2003, to the indenture, dated as of October 4, 2002, between MidAmerican Energy Holdings Company, or MEHC, and The Bank of New York, as trustee. The term "indenture" when used in this prospectus will refer to the indenture as amended by all supplemental indentures executed and delivered on or prior to the date on which the original series C notes were issued and sold (May 16, 2003). The terms of the series C notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended.

On October 4, 2002, MEHC issued $200,000,000 of its 4.625% Senior Notes due 2007 and $500,000,000 of its 5.875% Senior Notes due 2012 which are hereafter referred to as the series A notes and series B notes, respectively, pursuant to the indenture. Unless otherwise indicated, references hereafter to the notes in this prospectus include the series A notes, the series B notes and the series C notes (and any other series of notes or other securities hereafter issued under a supplemental indenture or otherwise pursuant to the indenture). The term series C notes when used in the prospectus will refer to the original series C notes and the series C exchange notes.

The following description is a summary of the material provisions of the indenture and the related registration rights agreement. It does not restate those agreements in their entirety. We urge you to read the indenture and the registration rights agreement because they, and not this description, define your rights as a holder of the series C notes. The definitions of certain capitalized terms used in the following summary are set forth below under "— Definitions."

General

The indenture does not limit the aggregate principal amount of the debt securities that may be issued thereunder and provides that debt securities may be issued from time to time in one or more series.

The original series C notes were initially offered in the aggregate principal amount of $450,000,000. MEHC may, without the consent of the holders, increase such principal amount in the future on the same terms and conditions and with the same CUSIP number(s) as the series C notes.

The original series C notes were, and the series C exchange notes will be, issued in one series, bear interest at the rate of 3.50% per annum and mature on May 15, 2008. Interest on the series C notes is payable semi-annually in arrears on each May 15 and November 15, commencing November 15, 2003, to the holders thereof at the close of business on the preceding May 1 and November 1, respectively. Interest on the series C notes is computed on the basis of a 360-day year of twelve 30-day months.

The original series C notes were, and the series C exchange notes will be, issued without coupons and in fully registered form only in denominations of $1,000 and any integral multiple of $1,000.

MEHC files certain reports and other information with the SEC in accordance with the requirements of Sections 13 and 15(d) under the Exchange Act. See "Where You Can Find More Information." In addition, at any time that Sections 13 and 15(d) cease to apply to MEHC, MEHC has covenanted in the indenture to file comparable reports and information with the trustee and the SEC, and mail such reports and information to holders of notes at their registered addresses, for so long as any notes remain outstanding.

If (i) the registration statement of which this prospectus is a part is not declared effective by the SEC within 270 days after the date on which the original series C notes were issued, (ii) a shelf registration statement with respect to the resale of the series C notes is not declared effective by the SEC within 150 days after MEHC's obligation to file such shelf registration statement arises (but in any event not prior to 270 days after the closing date for the original series C notes) or (iii) any of the foregoing registration statements (or the prospectuses related thereto) after being declared effective by the SEC cease to be so effective or usable (subject to certain exceptions) in connection with resales

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of the original series C notes or the series C exchange notes for the periods specified and in accordance with the registration rights agreement, the interest rate on the series C notes that are then subject to such cessation or other registration default will increase by 0.5% from and including the date on which any such event occurs until such event ceases to be continuing. The registration rights are more fully described under "Exchange Offer — Liquidated Damages."

Any original series C notes that remain outstanding after the consummation of the exchange offer, together with all series C exchange notes issued in connection with the exchange offer, will be treated as a single class of securities under the indenture.

Optional Redemption

General

The series C notes are redeemable in whole or in part, at the option of MEHC at any time, at a redemption price equal to the greater of:

(1) 100% of the principal amount of the series C notes being redeemed; or
(2) the sum of the present values of the remaining scheduled payments of principal of and interest on the series C notes being redeemed discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at a discount rate equal to the Treasury Yield plus 25 basis points,

plus, for (1) or (2) above, whichever is applicable, accrued interest on such series C notes to the date of redemption.

Notice of redemption shall be given not less than 30 days nor more than 60 days prior to the date of redemption. If fewer than all the series C notes are to be redeemed, selection of series C notes for redemption will be made by the trustee in any manner the trustee deems fair and appropriate.

Unless MEHC defaults in payment of the Redemption Price (as defined below), from and after the date of redemption the series C notes or portions of series C notes called for redemption will cease to bear interest, and the holders of those series C notes will have no right in respect of those series C notes except the right to receive the applicable Redemption Price.

Optional Redemption Provisions

Under the procedures described above, the price payable upon the optional redemption at any time of a series C note (the "Redemption Price") is determined by calculating the present value (the "Present Value") at such time of each remaining payment of principal of or interest on such series C note and then totaling those Present Values. If the sum of those Present Values is equal to or less than 100% of the principal amount of such series C note, the Redemption Price of such series C note will be 100% of its principal amount (redemption at par). If the sum of those Present Values is greater than 100% of the principal amount of such series C note, the Redemption Price of such series C note will be such greater amount (redemption at a premium). In no event may a series C note be redeemed optionally at less than 100% of its principal amount.

The Present Value at any time of a payment of principal of or interest on a series C note is calculated by applying to such payment the discount rate (the "Discount Rate") applicable to such payment. The Discount Rate applicable at any time to payment of principal of or interest on a series C note equals the equivalent yield to maturity at such time of a fixed rate United States treasury security having a maturity comparable to the maturity of such payment plus 25 basis points, such yield being calculated on the basis of the interest rate borne by such United States treasury security and the price at such time of such security. The United States treasury security employed in the calculation of a Discount Rate (a "Relevant Security") as well as the price and equivalent yield to maturity of such Relevant Security will be selected or determined by an Independent Investment Banker.

Whether the sum of the Present Values of the remaining payments of principal of and interest on a series C note to be redeemed optionally will or will not exceed 100% of its principal amount and, accordingly, whether such series C note will be redeemed at par or at a premium will depend on the

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Discount Rate used to calculate such Present Values. Such Discount Rate, in turn, will depend upon the equivalent yield to maturity of a Relevant Security, which yield will itself depend on the interest rate borne by, and the price of, the Relevant Security. While the interest rate borne by the Relevant Security is fixed, the price of the Relevant Security tends to vary with interest rate levels prevailing from time to time. In general, if at a particular time the prevailing level of interest rates for a newly issued United States treasury security having a maturity comparable to that of a Relevant Security is higher than the level of interest rates for newly issued United States treasury securities having a maturity comparable to such Relevant Security prevailing at the time the Relevant Security was issued, the price of the Relevant Security will be lower than its issue price. Conversely, if at a particular time the prevailing level of interest rates for a newly issued United States treasury security having a maturity comparable to that of a Relevant Security is lower than the level of interest rates prevailing for newly issued United States treasury securities having a maturity comparable to the Relevant Security at the time the Relevant Security was issued, the price of the Relevant Security will be higher than its issue price.

Because the equivalent yield to maturity on a Relevant Security depends on the interest rate it bears and its price, an increase or a decrease in the level of interest rates for newly issued United States treasury securities with a maturity comparable to that of a Relevant Security above or below the levels of interest rates for newly issued United States treasury securities having a maturity comparable to the Relevant Security prevailing at the time of issue of the Relevant Security will generally result in an increase or a decrease, respectively, in the Discount Rate used to determine the Present Value of a payment of principal of or interest on a series C note. An increase or a decrease in the Discount Rate, and therefore an increase or a decrease in the levels of interest rates for newly issued United States treasury securities having a maturity comparable to the Relevant Security, will result in a decrease or an increase, respectively, of the Present Value of a payment of principal of or interest on a series C note. In other words, the Redemption Price varies inversely with the levels of interest rates for newly issued United States treasury securities having a maturity comparable to the Comparable Treasury Issue. As noted above, however, if the sum of the Present Values of the remaining payments of principal of and interest on a series C note proposed to be redeemed is less than its principal amount, such series C note may only be redeemed at par.

Sinking Fund

The series C notes are not subject to any mandatory sinking fund.

Ranking

The series C notes are general, unsecured senior obligations of MEHC and rank pari passu in right of payment with all other existing and future senior unsecured obligations of MEHC (including the series A notes and series B notes) and senior in right of payment to all existing and future subordinated obligations of MEHC. The series C notes are effectively subordinated to all existing and future secured obligations of MEHC and to all existing and future obligations of MEHC's Subsidiaries. At March 31, 2003, MEHC's outstanding indebtedness was approximately $2.5 billion (excluding $2.1 billion in aggregate principal amount of MEHC's trust preferred securities, MEHC's guarantees and letters of credit in respect of subsidiary indebtedness aggregating approximately $231 million and MEHC's recently terminated completion guarantee issued in favor of the lenders under Kern River's recently refinanced $875 million construction loan facility in connection with Kern River's 2003 Expansion Project). In addition, MEHC's subsidiaries have significant amounts of indebtedness. At March 31, 2003, MEHC's consolidated subsidiaries' and joint ventures' total outstanding indebtedness was approximately $7.4 billion, which does not include $432 million, representing MEHC's share of outstanding indebtedness of CE Gen. This amount also does not include trade debt or preferred stock obligations of MEHC's subsidiaries.

Covenants

Except as set forth under "— Defeasance and Discharge" below, for so long as any notes remain outstanding, MEHC will comply with the terms of the covenants set forth below.

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Restrictions On Liens

MEHC is not permitted to pledge, mortgage, hypothecate or permit to exist any pledge, mortgage or other Lien upon any property or assets at any time directly owned by MEHC to secure any indebtedness for money borrowed which is incurred, issued, assumed or guaranteed by MEHC ("Indebtedness for Borrowed Money"), without making effective provisions whereby the outstanding notes will be equally and ratably secured with any and all such Indebtedness for Borrowed Money and with any other Indebtedness for Borrowed Money similarly entitled to be equally and ratably secured; provided however, that this restriction will not apply to or prevent the creation or existence of:

(1) any Liens existing prior to the issuance of the notes;
(2) purchase money Liens which do not exceed the cost or value of the purchased property or assets;
(3) any Liens not to exceed 10% of Consolidated Net Tangible Assets; and
(4) any Liens on property or assets granted in connection with extending, renewing, replacing or refinancing in whole or in part the Indebtedness for Borrowed Money (including, without limitation, increasing the principal amount of such Indebtedness for Borrowed Money) secured by Liens described in the foregoing clauses (1) through (3), provided that the Liens in connection with any such extension, renewal, replacement or refinancing will be limited to the specific property or assets that was subject to the original Lien.

In the event that MEHC proposes to pledge, mortgage or hypothecate or permit to exist any pledge, mortgage or other Lien upon any property or assets at any time directly owned by it to secure any Indebtedness for Borrowed Money, other than as permitted by clauses (1) through (4) of the previous paragraph, MEHC will give prior written notice thereof to the trustee and MEHC will, prior to or simultaneously with such pledge, mortgage or hypothecation, effectively secure all the notes equally and ratably with such Indebtedness for Borrowed Money.

The foregoing covenant will not restrict the ability of MEHC's Subsidiaries and affiliates to pledge, mortgage, hypothecate or permit to exist any mortgage, pledge or Lien upon their property or assets, in connection with project financings or otherwise.

Consolidation, Merger, Conveyance, Sale or Lease

MEHC is not permitted to consolidate with or merge with or into any other person, or convey, transfer or lease its consolidated properties and assets substantially as an entirety to any person, or permit any person to merge into or consolidate with MEHC, unless (1) MEHC is the surviving or continuing corporation or the surviving or continuing corporation or purchaser or lessee is a corporation incorporated under the laws of the United States of America, one of the States thereof or the District of Columbia or Canada and assumes MEHC's obligations under the notes and under the indenture and (2) immediately before and after such transaction, no event of default under the indenture shall have occurred and be continuing.

Except for a sale of the consolidated properties and assets of MEHC substantially as an entirety as provided above, and other than properties or assets required to be sold to conform with laws or governmental regulations, MEHC is not permitted, directly or indirectly, to sell or otherwise dispose of any of its consolidated properties or assets (other than short-term, readily marketable investments purchased for cash management purposes with funds not representing the proceeds of other asset sales) if on a pro forma basis, the aggregate net book value of all such sales during the most recent 12-month period would exceed 10% of Consolidated Net Tangible Assets computed as of the end of the most recent quarter preceding such sale; provided, however, that (1) any such sales shall be disregarded for purposes of this 10% limitation if the net proceeds are invested in properties or assets in similar or related lines of business of MEHC and its Subsidiaries, including, without limitation, any of the lines of business in which MEHC or any of its Subsidiaries is engaged on the date of such sale or disposition, and (2) MEHC may sell or otherwise dispose of consolidated properties and assets in excess of such 10% limitation if the net proceeds from such sales or dispositions, which are not

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reinvested as provided above, are retained by MEHC as cash or Cash Equivalents or used to retire Indebtedness for Borrowed Money of MEHC (other than Indebtedness for Borrowed Money which is subordinated to the notes) and its Subsidiaries.

Purchase of Notes Upon a Change of Control

Upon the occurrence of a Change of Control, each holder of the notes will have the right to require that MEHC repurchase all or any part of such holder's notes at a purchase price in cash equal to 101% of the principal thereof on the date of purchase plus accrued interest, if any, to the date of purchase.

The Change of Control provisions may not be waived by the trustee or by the board of directors of MEHC, and any modification thereof must be approved by each holder. Nevertheless, the Change of Control provisions will not necessarily afford protection to holders, including protection against an adverse effect on the value of the notes of any series, in the event that MEHC or its Subsidiaries incur additional Debt, whether through recapitalizations or otherwise.

Within 30 days following a Change of Control, MEHC will mail a notice to each holder of the notes with a copy to the trustee, stating the following:

(1) that a Change of Control has occurred and that such holder has the right to require MEHC to purchase such holder's notes at the purchase price described above (the "Change of Control Offer");
(2) the circumstances and relevant facts regarding such Change of Control (including information with respect to pro forma historical income, cash flow and capitalization after giving effect to such Change of Control);
(3) the purchase date (which will be not earlier than 30 days nor later than 60 days from the date such notice is mailed) (the "Purchase Date");
(4) that after the Purchase Date interest on such note will continue to accrue (except as provided in clause (5));
(5) that any note properly tendered pursuant to the Change of Control Offer will cease to accrue interest after the Purchase Date (assuming sufficient moneys for the purchase thereof are deposited with the trustee);
(6) that holders electing to have a note purchased pursuant to a Change of Control Offer will be required to surrender the note, with the form entitled "Option of Holder To Elect Purchase" on the reverse of the note completed, to the paying agent at the address specified in the notice prior to the close of business on the fifth business day prior to the Purchase Date;
(7) that a holder will be entitled to withdraw such holder's election if the paying agent receives, not later than the close of business on the third business day (or such shorter periods as may be required by applicable law) preceding the Purchase Date, a telegram, telex, facsimile transmission or letter setting forth the name of the holder, the principal amount of notes the holder delivered for purchase, and a statement that such holder is withdrawing his election to have such notes of such series purchased; and
(8) that holders that elect to have their notes purchased only in part will be issued new notes having a principal amount equal to the portion of the notes that were surrendered but not tendered and purchased.

On the Purchase Date, MEHC will (1) accept for payment all notes or portions thereof tendered pursuant to the Change of Control Offer, (2) deposit with the trustee money sufficient to pay the purchase price of all notes or portions thereof so tendered for purchase and (3) deliver or cause to be delivered to the trustee the notes properly tendered together with an officer's certificate identifying the notes or portions thereof tendered to MEHC for purchase. The trustee will promptly mail, to the holders of the notes properly tendered and purchased, payment in an amount equal to the purchase price, and promptly authenticate and mail to each holder a new note having a principal amount equal

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to any portion of such holder's notes that were surrendered but not tendered and purchased. MEHC will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Purchase Date.

If MEHC is prohibited by applicable law from making the Change of Control Offer or purchasing notes of any series thereunder, MEHC need not make a Change of Control Offer pursuant to this covenant for so long as such prohibition is in effect.

MEHC will comply with all applicable tender offer rules, including, without limitation, Rule 14e-1 under the Exchange Act, in connection with a Change of Control Offer.

Events of Default

An event of default with respect to the notes of any series will be defined in the indenture as being any one of the following events:

(1) default as to the payment of interest on any note of that series for 30 days after payment is due;
(2) default as to the payment of principal of, or premium, if any, on any note of that series or as to any payment required in connection with a Change of Control;
(3) failure to make a Change of Control Offer required under the covenants described under "Purchase of Notes Upon a Change of Control" above or a failure to purchase the notes of that series tendered in respect of such Change of Control Offer;
(4) default in the performance, or breach, of any covenant, agreement or warranty of MEHC contained in the indenture and the notes of that series and such failure continues for 30 days after written notice is given to MEHC by the trustee or to MEHC and the trustee by the holders of at least a majority in aggregate principal amount outstanding of the notes of that series, as provided in the indenture;
(5) default on any other Debt of MEHC or any Significant Subsidiary (other than Debt that is Non-Recourse to MEHC) if either (x) such default results from failure to pay principal of such Debt in excess of $100 million when due after any applicable grace period or (y) as a result of such default, the maturity of such Debt has been accelerated prior to its scheduled maturity and such default has not been cured within the applicable grace period, and such acceleration has not been rescinded, and the principal amount of such Debt, together with the principal amount of any other Debt of MEHC and its Significant Subsidiaries (not including Debt that is Non-Recourse to MEHC) that is in default as to principal, or the maturity of which has been accelerated, aggregates $100 million or more;
(6) the entry by a court of one or more judgments or orders against MEHC or any Significant Subsidiary for the payment of money that in the aggregate exceeds $100 million (excluding (i) the amount thereof covered by insurance or by a bond written by a person other than an affiliate of MEHC (other than, with respect to the series C notes, Berkshire Hathaway or any of its affiliates that provide commercial insurance in the ordinary course of their business) and (ii) judgments that are Non-Recourse to MEHC), which judgments or orders have not been vacated, discharged or satisfied or stayed pending appeal within 60 days from the entry thereof, provided that such a judgment or order will not be an event of default if such judgment or order does not require any payment by MEHC; and
(7) certain events involving bankruptcy, insolvency or reorganization of MEHC or any of its Significant Subsidiaries.

The indenture provides that the trustee may withhold notice to the holders of any default (except in payment of principal of, premium, if any, or interest on any series of notes and any payment required in connection with a Change of Control) if the trustee considers it in the interest of holders to do so.

The indenture provides that if an event of default with respect to the notes of any series at the time outstanding (other than an event of bankruptcy, insolvency or reorganization of MEHC or a

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Significant Subsidiary) has occurred and is continuing, either the trustee or (i) in the case of any event of default described in clause (1) or (2) above, the holders of at least 33% in aggregate principal amount of the notes of that series then outstanding, or (ii) in the case of any other event of default, the holders of at least a majority in aggregate principal amount of the notes of that series then outstanding, may declare the principal of and any accrued interest on all notes of that series to be due and payable immediately, but upon certain conditions such declaration may be annulled and past defaults (except, unless theretofore cured, a default in payment of principal of, premium, if any, or interest on the notes of that series or any payment required in connection with a Change of Control) may be waived by the holders of a majority in principal amount of the notes of that series then outstanding. If an event of default due to the bankruptcy, insolvency or reorganization of MEHC or a Significant Subsidiary occurs, the indenture provides that the principal of and interest on all notes will become immediately due and payable without any action by the trustee, the holders of notes or any other person.

The holders of a majority in principal amount of the notes of any series then outstanding will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee under the indenture with respect to the notes of such series, subject to certain limitations specified in the indenture, provided that the holders of notes of such series must have offered to the trustee reasonable indemnity against expenses and liabilities.

The indenture requires the annual filing by MEHC with the trustee of a written statement as to its knowledge of the existence of any default in the performance and observance of any of the covenants contained in the indenture.

Modification of the Indenture

The indenture contains provisions permitting MEHC and the trustee, with the consent of the holders of not less than a majority in principal amount of the outstanding notes of each series affected by the modification, to modify the indenture or the rights of the holders of such series, except that no such modification may (1) extend the stated maturity of the principal of or any installment of interest on the notes, reduce the principal amount thereof or the interest rate thereon, reduce any premium payable on redemption or purchase thereof, impair the right of any holder to institute suit for the enforcement of any such payment on or after the stated maturity thereof or make any change in the covenants regarding a Change of Control or the related definitions without the consent of the holder of each outstanding note so affected, or (2) reduce the percentage of any series of notes, the consent of the holders of which is required for any such modification, without the consent of the holders of all series of notes then outstanding.

Defeasance and Discharge

Legal Defeasance

The indenture provides that MEHC will be deemed to have paid and will be discharged from any and all obligations in respect of the notes of any series on the 123rd day after the deposit referred to below has been made (or immediately if an opinion of counsel is delivered to the effect described in clause (B)(3)(y) below), and the provisions of the indenture will cease to be applicable with respect to the notes of such series (except for, among other matters, certain obligations to register the transfer or exchange of the notes of such series, to replace stolen, lost or mutilated notes of such series, to maintain paying agents and to hold monies for payment in trust) if, among other things:

(A) MEHC has deposited with the trustee, in trust, money and/or U.S. Government Obligations that through the payment of interest and principal in respect thereof in accordance with their terms will provide money in an amount sufficient to pay the principal of, premium, if any, and accrued and unpaid interest on the applicable notes, on the respective stated maturities of the notes or, if MEHC makes arrangements satisfactory to the trustee for the redemption of the notes prior to their stated maturity, on any earlier redemption date in accordance with the terms of the indenture and the applicable notes;

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(B) MEHC has delivered to the trustee:
(1) either (x) an opinion of counsel to the effect that holders will not recognize income, gain or loss for federal income tax purposes as a result of such deposit, defeasance and discharge and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit, defeasance and discharge had not occurred and MEHC had paid or redeemed such notes on the applicable dates, which opinion of counsel must be based upon a ruling of the Internal Revenue Service to the same effect or a change in applicable federal income tax law or related Treasury regulations after the date of the indenture, or (y) a ruling directed to the trustee or MEHC received from the Internal Revenue Service to the same effect as the aforementioned opinion of counsel;
(2) an opinion of counsel to the effect that the creation of the defeasance trust does not violate the Investment Company Act of 1940; and
(3) an opinion of counsel to the effect that either (x) after the passage of 123 days following the deposit referred to in clause (A) above, the trust fund will not be subject to the effect of Section 547 or 548 of the U.S. Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law or (y) based upon existing precedents, if the matter were properly briefed, a court should hold that the deposit of moneys and/or U.S. Government Obligations as provided in clause (A) above would not constitute a preference voidable under Section 547 or 548 of the U.S. Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law;
(C) immediately after giving effect to such deposit referred to in clause (A) above on a pro forma basis, no event of default under the indenture, or event that after the giving of notice or lapse of time or both would become an event of default, will have occurred and be continuing on the date of such deposit or (unless an opinion of counsel is delivered to the effect described in clause (B)(3)(y) above) during the period ending on the 123rd day after the date of such deposit, and such deposit and discharge will not result in a breach or violation of, or constitute a default under, any other material agreement or instrument to which MEHC is a party or by which MEHC is bound; and
(D) if at such time the notes are listed on a national securities exchange, MEHC has delivered to the trustee an opinion of counsel to the effect that the notes will not be delisted as a result of such deposit, defeasance and discharge.

Covenant Defeasance

The indenture further provides that the provisions of the covenants described herein under "Covenants — Restrictions on Liens", "— Consolidation, Merger, Conveyance, Sale or Lease" and "— Purchase of Notes Upon a Change of Control," clauses (3) and (4) under "Events of Default" with respect to such covenants, clause (2) under "Events of Default" with respect to offers to purchase upon a Change of Control as described above and clauses (5) and (6) under "Events of Default" will cease to be applicable to MEHC and its Subsidiaries upon the satisfaction of the provisions described in clauses (A), (B), (C) and (D) of the preceding paragraph; provided, however, that with respect to such covenant defeasance, the opinion of counsel described in clause (B)(1)(x) above need not be based upon any ruling of the Internal Revenue Service or change in applicable federal income tax law or related Treasury regulations.

Defeasance and Certain Other Events of Default

If MEHC exercises its option to omit compliance with certain covenants and provisions of the indenture with respect to the notes of any series as described in the immediately preceding paragraph and any series of notes is declared due and payable because of the occurrence of an event of default that remains applicable, the amount of money and/or U.S. Government Obligations on deposit with the trustee will be sufficient to pay amounts due on such notes at the time of their stated maturity or

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scheduled redemption, but may not be sufficient to pay amounts due on such notes at the time of acceleration resulting from such event of default. MEHC will remain liable for such payments.

Governing Law

The indenture and the notes are governed by, and construed in accordance with, the law of the State of New York, including Section 5-1401 of the New York General Obligations Law, but otherwise without regard to conflict of laws rules.

Trustee

The Bank of New York is the trustee under the indenture. The Bank of New York (or one of its affiliates) currently serves, and may in the future serve, as trustee under indentures evidencing other indebtedness of MEHC and its affiliates. The Bank of New York (or one of its affiliates) is also, and may in the future be, a lender under credit facilities for MEHC and its affiliates.

Definitions

Set forth below is a summary of certain of the defined terms used in the covenants and other provisions of the indenture. Reference is made to the indenture for the full definitions of all such terms as well as any other capitalized terms used herein for which no definition is provided.

"Attributable Value" means, as to a Capitalized Lease Obligation under which any person is at the time liable and at any date as of which the amount thereof is to be determined, the capitalized amount thereof that would appear on the face of a balance sheet of such person in accordance with GAAP.

"Berkshire Hathaway" means Berkshire Hathaway Inc. and any Subsidiary of Berkshire Hathaway Inc.

"Capital Stock" means, with respect to any person, any and all shares, interests, participations or other equivalents (however designated, whether voting or non-voting) in, or interests (however designated) in, the equity of such person that is outstanding or issued on or after the date of the indenture, including, without limitation, all common stock and preferred stock and partnership and joint venture interests in such person.

"Capitalized Lease" means, as applied to any person, any lease of any property of which the discounted present value of the rental obligations of such person as lessee, in conformity with GAAP, is required to be capitalized on the balance sheet of such person, and "Capitalized Lease Obligation" means the rental obligations, as aforesaid, under such lease.

"Cash Equivalent" means any of the following:

(1) securities issued or directly and fully guaranteed or insured by the United States of America or any agency or instrumentality thereof (provided that the full faith and credit of the United States of America is pledged in support thereof);
(2) time deposits and certificates of deposit of any commercial bank organized in the United States having capital and surplus in excess of $500,000,000 or any commercial bank organized under the laws of any other country having total assets in excess of $500,000,000 with a maturity date not more than two years from the date of acquisition;
(3) repurchase obligations with a term of not more than 30 days for underlying securities of the types described in clauses (1) or (5) of this definition that were entered into with any bank meeting the qualifications set forth in clause (2) of this definition or another financial institution of national reputation;
(4) direct obligations issued by any state or other jurisdiction of the United States of America or any other country or any political subdivision or public instrumentality thereof maturing, or subject to tender at the option of the holder thereof, within 90 days after the date of

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acquisition thereof and, at the time of acquisition, having a rating of at least A from S&P or A-2 from Moody's (or, if at any time neither S&P nor Moody's may be rating such obligations, then from another nationally recognized rating service acceptable to the trustee);
(5) commercial paper issued by (a) the parent corporation of any commercial bank organized in the United States having capital and surplus in excess of $500,000,000 or any commercial bank organized under the laws of any other country having total assets in excess of $500,000,000, and (b) others having one of the two highest ratings obtainable from either S&P or Moody's (or, if at any time neither S&P nor Moody's may be rating such obligations, then from another nationally recognized rating service acceptable to the trustee) and in each case maturing within one year after the date of acquisition;
(6) overnight bank deposits and bankers' acceptances at any commercial bank organized in the United States having capital and surplus in excess of $500,000,000 or any commercial bank organized under the laws of any other country having total assets in excess of $500,000,000;
(7) deposits available for withdrawal on demand with any commercial bank organized in the United States having capital and surplus in excess of $500,000,000 or any commercial bank organized under the laws of any other country having total assets in excess of $500,000,000;
(8) investments in money market funds substantially all of whose assets comprise securities of the types described in clauses (1) through (6) and (9) of this definition; and
(9) auction rate securities or money market preferred stock having one of the two highest ratings obtainable from either S&P or Moody's (or, if at any time neither S&P nor Moody's may be rating such obligations, then from another nationally recognized rating service acceptable to the trustee).

"Change of Control" means the occurrence of one or more of the following events:

(1) a transaction pursuant to which Berkshire Hathaway ceases to own, on a diluted basis (assuming conversion of all of MEHC's convertible preferred stock and any other Capital Stock of MEHC that is issued and outstanding, regardless of whether any such convertible preferred stock or other Capital Stock is then presently convertible), at least a majority of the issued and outstanding common stock of MEHC; or
(2) MEHC or its Subsidiaries sell, convey, assign, transfer, lease or otherwise dispose of all or substantially all the property of MEHC and its Subsidiaries taken as a whole to any person or entity other than an entity at least a majority of the issued and outstanding common stock of which is owned by Berkshire Hathaway, calculated on a diluted basis as described above;

provided that with respect to the foregoing subparagraphs (1) and (2), a Change of Control will not be deemed to have occurred unless and until a Rating Decline has occurred as well.

"Comparable Treasury Issue" means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term of notes of any series to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes.

"Comparable Treasury Price" means, with respect to any Redemption Date, (1) the average of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) on the third business day preceding such Redemption Date, as set forth in the daily statistical release (or any successor release) published by the Federal Reserve Bank of New York and designated "Composite 3:30 p.m. Quotations for U.S. Government Securities" or (2) if such release (or any successor release) is not published or does not contain such prices on such business day, the Reference Treasury Dealer Quotation for such Redemption Date.

"Consolidated Net Tangible Assets" means, as of the date of any determination thereof, the total amount of all assets of MEHC determined on a consolidated basis in accordance with GAAP as of

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such date less the sum of (a) the consolidated current liabilities of MEHC determined in accordance with GAAP and (b) assets properly classified as Intangible Assets.

"Currency Protection Agreement" means, with respect to any person, any foreign exchange contract, currency swap agreement or other similar agreement or arrangement intended to protect such person against fluctuations in currency values to or under which such person is a party or a beneficiary on the date of the indenture or becomes a party or a beneficiary thereafter.

"Debt" means, with respect to any person, at any date of determination (without duplication):

(1) all Indebtedness for Borrowed Money of such person;
(2) all obligations of such person evidenced by bonds, debentures, notes or other similar instruments;
(3) all obligations of such person in respect of letters of credit, bankers' acceptances, surety, bid, operating and performance bonds, performance guarantees or other similar instruments or obligations (or reimbursement obligations with respect thereto) (except, in each case, to the extent incurred in the ordinary course of business);
(4) all obligations of such person to pay the deferred purchase price of property or services, except Trade Payables;
(5) the Attributable Value of all obligations of such person as lessee under Capitalized Leases;
(6) all Debt of others secured by a Lien on any Property of such person, whether or not such Debt is assumed by such person, provided that, for purposes of determining the amount of any Debt of the type described in this clause, if recourse with respect to such Debt is limited to such Property, the amount of such Debt will be limited to the lesser of the fair market value of such Property or the amount of such Debt;
(7) all Debt of others Guaranteed by such person to the extent such Debt is Guaranteed by such person;
(8) all Redeemable Stock valued at the greater of its voluntary or involuntary liquidation preference plus accrued and unpaid dividends; and
(9) to the extent not otherwise included in this definition, all net obligations of such person under Currency Protection Agreements and Interest Rate Protection Agreements.

For purposes of determining any particular amount of Debt that is or would be outstanding, Guarantees of, or obligations with respect to letters of credit or similar instruments supporting (to the extent the foregoing constitutes Debt), Debt otherwise included in the determination of such particular amount will not be included. For purposes of determining compliance with the indenture, in the event that an item of Debt meets the criteria of more than one of the types of Debt described in the above clauses, MEHC, in its sole discretion, will classify such item of Debt and only be required to include the amount and type of such Debt in one of such clauses.

"Guarantee" means any obligation, contingent or otherwise, of any person directly or indirectly guaranteeing any Debt of any other person and, without limiting the generality of the foregoing, any Debt obligation, direct or indirect, contingent or otherwise, of such person (1) to purchase or pay (or advance or supply funds for the purchase or payment of) such Debt of such other person (whether arising by virtue of partnership arrangements (other than solely by reason of being a general partner of a partnership), or by agreement to keep-well, to purchase assets, goods, securities or services or to take-or-pay, or to maintain financial statement conditions or otherwise) or (2) entered into for purposes of assuring in any other manner the obligee of such Debt of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part), provided that the term "Guarantee" will not include endorsements for collection or deposit in the ordinary course of business or the grant of a lien in connection with any Non-Recourse Debt. The term "Guarantee" used as a verb has a corresponding meaning.

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"Independent Investment Banker" means an independent investment banking institution of international standing appointed by MEHC.

"Intangible Assets" means, as of the date of determination thereof, all assets of MEHC properly classified as intangible assets determined on a consolidated basis in accordance with GAAP. "Interest Rate Protection Agreement" means, with respect to any person, any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement intended to protect such person against fluctuations in interest rates to or under which such person or any of its Subsidiaries is a party or a beneficiary on the date of the indenture or becomes a party or a beneficiary thereafter.

"Investment Grade" means with respect to the notes, (1) in the case of S&P, a rating of at least BBB–, (2) in the case of Moody's, a rating of at least Baa3, and (3) in the case of a Rating Agency other than S&P or Moody's, the equivalent rating, or in each case, any successor, replacement or equivalent definition as promulgated by S&P, Moody's or other Rating Agency as the case may be.

"Joint Venture" means a joint venture, partnership or other similar arrangement, whether in corporate, partnership or other legal form.

"Lien" means, with respect to any Property, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such Property, but will not include any partnership, joint venture, shareholder, voting trust or similar governance agreement with respect to Capital Stock in a Subsidiary or Joint Venture. For purposes of the indenture, MEHC will be deemed to own subject to a Lien any Property that it has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement relating to such Property.

"Non-Recourse" means any Debt or other obligation (or that portion of such Debt or other obligation) that is without recourse to MEHC or any property or assets directly owned by MEHC (other than a pledge of the equity interests in any Subsidiary of MEHC, to the extent recourse to MEHC under such pledge is limited to such equity interests).

"Property" of any person means all types of real, personal, tangible or mixed property owned by such person whether or not included in the most recent consolidated balance sheet of such person under GAAP.

"Rating Agencies" means (1) S&P and (2) Moody's or (3) if S&P or Moody's or both do not make a rating of the notes publicly available, a nationally recognized securities rating agency or agencies, as the case may be, selected by MEHC, which will be substituted for S&P, Moody's or both, as the case may be.

"Rating Category" means (1) with respect to S&P, any of the following categories: BB, B, CCC, CC, C and D (or equivalent successor categories), (2) with respect to Moody's, any of the following categories: Ba, B, Caa, Ca, C and D (or equivalent successor categories) and (3) the equivalent of any such category of S&P or Moody's used by another Rating Agency. In determining whether the rating of the notes has decreased by one or more gradations, gradations within Rating Categories (+ and – for S&P, 1, 2 and 3 for Moody's or the equivalent gradations for another Rating Agency) will be taken into account (e.g., with respect to S&P, a decline in a rating from BB+ to BB, as well as from BB– to B+, will constitute a decrease of one gradation).

"Rating Decline" means the occurrence of the following on, or within 90 days after, the earlier of (1) the occurrence of a Change of Control and (2) the date of public notice of the occurrence of a Change of Control or of the public notice of the intention of MEHC to effect a Change of Control (the "Rating Date"), which period will be extended so long as the rating of the notes is under publicly announced consideration for possible downgrading by any of the Rating Agencies: (a) in the event that any series of the notes are rated by either Rating Agency on the Rating Date as Investment Grade, the rating of such notes by both such Rating Agencies is reduced below Investment Grade, or (b) in the event the notes are rated below Investment Grade by both such Rating Agencies on the

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Rating Date, the rating of such notes by either Rating Agency is decreased by one or more gradations (including gradations within Rating Categories as well as between Rating Categories).

"Redeemable Stock" means any class or series of Capital Stock of any person that by its terms or otherwise is (1) required to be redeemed prior to the stated maturity of any series of the notes, (2) redeemable at the option of the holder of such class or series of Capital Stock at any time prior to the stated maturity of any series of the notes or (3) convertible into or exchangeable for Capital Stock referred to in clause (1) or (2) above or Debt having a scheduled maturity prior to the stated maturity of any series of the notes, provided that any Capital Stock that would not constitute Redeemable Stock but for provisions thereof giving holders thereof the right to require MEHC to purchase or redeem such Capital Stock upon the occurrence of a "change of control" occurring prior to the stated maturity of any series of the notes will not constitute Redeemable Stock if the "change of control" provisions applicable to such Capital Stock are no more favorable to the holders of such Capital Stock than the provisions contained in the covenants described under "Purchase of Notes Upon a Change of Control" above.

"Redemption Date" means any date on which MEHC redeems all or any portion of the notes in accordance with the terms of the indenture.

"Reference Treasury Dealer" means a primary U.S. government securities dealer in New York City appointed by MEHC.

"Reference Treasury Dealer Quotation" means, with respect to the Reference Treasury Dealer and any Redemption Date, the average, as determined by MEHC, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount and quoted in writing to MEHC by such Reference Treasury Dealer at 5:00 p.m. on the third business day preceding such Redemption Date).

"Significant Subsidiary" means a "significant subsidiary" as defined in Rule 1-02(w) of Regulation S-X under the Securities Act and the Exchange Act, substituting 20 percent for 10 percent each place it appears therein. Unless the context otherwise clearly requires, any reference to a "Significant Subsidiary" is a reference to a Significant Subsidiary of MEHC.

"Subsidiary" means, with respect to any person including, without limitation, MEHC and its Subsidiaries, any corporation or other entity of which such person owns, directly or indirectly, a majority of the Capital Stock or other ownership interests and has ordinary voting power to elect a majority of the board of directors or other persons performing similar functions.

"Trade Payables" means, with respect to any person, any accounts payable or any other indebtedness or monetary obligation to trade creditors incurred, created, assumed or Guaranteed by such person or any of its Subsidiaries or Joint Ventures arising in the ordinary course of business.

"Treasury Yield" means, with respect to any Redemption Date, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such Redemption Date.

"U.S. Government Obligations" means any securities that are (1) direct obligations of the United States for the payment of which its full faith and credit is pledged or (2) obligations of a person controlled or supervised by and acting as an agency or instrumentality of the United States, the payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States, that, in either case are not callable or redeemable at the option of the issuer thereof, and will also include any depository receipt issued by a bank or trust company as custodian with respect to any such U.S. Government Obligations or a specific payment of interest on or principal of any such U.S. Government Obligation held by such custodian for the account of the holder of a depository receipt, provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the U.S. Government Obligation or the specific payment of interest on or principal of the U.S. Government Obligation evidenced by such depository receipt.

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"Voting Stock" means, with respect to any person, Capital Stock of any class or kind ordinarily having the power to vote for the election of directors (or persons fulfilling similar responsibilities) of such person.

Global Notes; Book-Entry System

The original series C notes were, and the series C exchange notes will be, issued under a book-entry system in the form of one or more global notes (each, a "Global Note"). Each Global Note with respect to the original series C notes was, and each Global Note with respect to the series C exchange notes will be, deposited with, or on behalf of, a depositary, which is The Depository Trust Company, New York, New York (the "Depositary"). The Global Notes with respect to the original series C notes were, and the Global Notes with respect to the series C exchange notes will be, registered in the name of the Depositary or its nominee.

The original series C notes were not issued in certificated form and, except under the limited circumstances described below, owners of beneficial interests in the Global Notes are not entitled to physical delivery of the series C notes in certificated form. The Global Notes may not be transferred except as a whole by the Depositary to a nominee of the Depositary or by a nominee of the Depositary to the Depositary or another nominee of the Depositary or by the Depositary or any nominee to a successor of the Depositary or a nominee of such successor.

The Depositary is a limited-purpose trust company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code, and a "clearing agency" registered pursuant to the provisions of Section 17A of the Exchange Act. The Depositary holds securities that its participants ("Direct Participants") deposit with the Depositary. The Depositary also facilitates the post-trade settlement among Direct Participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in Direct Participants' accounts, thereby eliminating the need for physical movement of securities certificates. Direct Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations, including Euroclear Bank S.A./N.V. as operator of the Euroclear System ("Euroclear") and Clearstream Banking, societe anonyme ("Clearstream"). The Depositary is a wholly owned subsidiary of The Depository Trust & Clearing Corporation ("DTCC"). DTCC, in turn, is owned by a number of Direct Participants and Members of the National Securities Clearing Corporation, Government Securities Clearing Corporation, MBS Clearing Corporation and Emerging Markets Clearing Corporation, also subsidiaries of DTCC, as well as by the New York Stock Exchange, Inc., the American Stock Exchange LLC and the National Association of Securities Dealers, Inc. Access to the Depositary system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly ("Indirect Participants"). The rules applicable to the Depositary and its Direct and Indirect Participants are on file with the SEC.

Purchases of the notes under the Depositary system must be made by or through Direct Participants, which will receive a credit for the notes on the Depositary's records. The ownership interest of each actual purchaser of each note ("Beneficial Owner") is in turn to be recorded on the Direct and Indirect Participants' records. Beneficial Owners will not receive written confirmation from the Depositary of their purchase, but Beneficial Owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which the Beneficial Owner entered into the transaction. Transfers of ownership interests in the notes are to be accomplished by entries made on the books of Direct and Indirect Participants acting on behalf of Beneficial Owners. Beneficial Owners will not receive certificates representing their ownership interests in notes, except in the event that use of the book-entry system for the notes is discontinued.

To facilitate subsequent transfers, all series C notes deposited by Direct Participants with the Depositary are registered in the name of the Depositary's partnership nominee, Cede & Co., or such

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other name as may be requested by an authorized representative of the Depositary. The deposit of series C notes with the Depositary and their registration in the name of Cede & Co. or such other nominee effect no change in beneficial ownership. The Depositary has no knowledge of the actual Beneficial Owners of the series C notes; the Depositary's records reflect only the identity of the Direct Participants to whose accounts such series C notes are credited, which may or may not be the Beneficial Owners. The Direct and Indirect Participants remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by the Depositary to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners are governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

Neither the Depositary nor Cede & Co. (nor any other nominee of the Depositary) will consent or vote with respect to the series C notes unless authorized by a Direct Participant in accordance with the Depositary's procedures. Under its usual procedures, the Depositary mails an Omnibus Proxy to MEHC as soon as possible after the record date. The Omnibus Proxy assigns Cede & Co.'s consenting or voting rights to those Direct Participants to whose accounts the notes are credited on the record date (identified in a listing attached to the Omnibus Proxy).

Principal (and premium, if any) and interest payments on the series C notes and any redemption payments are made to Cede & Co. (or such other nominee as may be requested by an authorized representative of the Depositary). The Depositary's practice is to credit Direct Participants' accounts upon the Depositary's receipt of funds and corresponding detail information from MEHC or the trustee on the payable date in accordance with their respective holdings shown on the Depositary's records. Payments by Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in "street name," and will be the responsibility of such Participant and not of the Depositary, the trustee or MEHC, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of principal (and premium, if any), interest and any redemption proceeds to Cede & Co. (or such other nominee as may be requested by an authorized representative of the Depositary) is the responsibility of MEHC, disbursements of such payments to Direct Participants shall be the responsibility of the Depositary, and disbursement of such payments to the Beneficial Owners shall be the responsibility of Direct and Indirect Participants.

The Depositary may discontinue providing its services as securities depositary with respect to the series C notes at any time by giving reasonable notice to MEHC or the trustee. Under such circumstances, in the event that a successor securities depositary is not obtained, certificated series C notes are required to be printed and delivered. MEHC may decide to discontinue use of the system of book-entry transfers through the Depositary (or a successor securities depositary). In that event, certificated series C notes will be printed and delivered.

The information in this section concerning the Depositary and the Depositary's book-entry system has been obtained from sources that MEHC believes to be reliable, but MEHC, the initial purchasers and the trustee take no responsibility for the accuracy thereof.

A Global Note of any series may not be transferred except as a whole by the Depositary to a nominee or successor of the Depositary or by a nominee of the Depositary to another nominee of the Depositary. A Global Note representing series C notes is exchangeable, in whole but not in part, for series C notes in definitive form of like tenor and terms if (1) the Depositary notifies MEHC that it is unwilling or unable to continue as depositary for such Global Note or if at any time the Depositary is no longer eligible to be or in good standing as a "clearing agency" registered under the Exchange Act, and in either case, a successor depositary is not appointed by MEHC within 120 days of receipt by MEHC of such notice or of MEHC becoming aware of such ineligibility, (2) while such Global Note is subject to the transfer restrictions described under "Transfer Restrictions," the book-entry interests in such Global Note cease to be eligible for Depositary services because such series C notes are neither (a) rated in one of the top four categories by a nationally recognized statistical rating organization nor (b) included within a Self-Regulatory Organization system approved by the SEC for the reporting of

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quotation and trade information of securities eligible for transfer pursuant to Rule 144A under the Securities Act, or (3) MEHC in its sole discretion at any time determines not to have such series C notes represented by a Global Note and notifies the trustee thereof. A Global Note exchangeable pursuant to the preceding sentence shall be exchangeable for series C notes registered in such names and in such authorized denominations as the Depositary shall direct.

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CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The exchange of original series C notes for series C exchange notes pursuant to the exchange offer will not constitute a taxable event for U.S. federal income tax purposes. The series C exchange notes received by a holder of original series C notes should be treated as a continuation of such holder's investment in the original series C notes; thus there should be no material U.S. federal income tax consequences to holders exchanging original series C notes for series C exchange notes. As a result:

• a holder of original series C notes will not recognize taxable gain or loss as a result of the exchange of original series C notes for series C exchange notes pursuant to the exchange offer;
• the holding period of the series C exchange notes will include the holding period of the original series C notes surrendered in exchange therefor; and
• a holder's adjusted tax basis in the series C exchange notes will be the same as such holder's adjusted tax basis in the original series C notes surrendered in exchange therefor.

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PLAN OF DISTRIBUTION

Based on existing interpretations of the Securities Act by the staff of the SEC set forth in several no-action letters to third parties, and subject to the immediately following sentence, we believe that the series C exchange notes that will be issued pursuant to the exchange offer may be offered for resale, resold and otherwise transferred by the holders thereof without further compliance with the registration and prospectus delivery provisions of the Securities Act. However, any purchaser of series C notes who is an "affiliate" (within the meaning of the Securities Act) of ours or who intends to participate in the exchange offer for the purpose of distributing the series C exchange notes or a broker-dealer (within the meaning of the Securities Act) that acquired original series C notes in a transaction other than as part of its market-making or other trading activities and who has arranged or has an understanding with any person to participate in the distribution of the series C exchange notes: (1) will not be able to rely on the interpretations by the staff of the SEC set forth in the above-mentioned no-action letters; (2) will not be able to tender its original series C notes in the exchange offer; and (3) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the series C notes unless such sale or transfer is made pursuant to an exemption from such requirements.

Each broker-dealer that receives series C exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such series C exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of series C exchange notes received in exchange for original series C notes where such original series C notes were acquired as a result of market-marketing activities or other trading activities. We have agreed that, for a period of 120 days after the expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until July 22, 2003, all dealers effecting transactions in the series C exchange notes may be required to deliver a prospectus.

We will not receive any proceeds from any such sale of series C exchange notes by broker-dealers. Series C exchange notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the series C exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker/dealer and/or the purchasers of any such series C exchange notes. Any broker-dealer that resells series C exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such series C exchange notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit on any such resale of series C exchange notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letters of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

For a period of 120 days after the expiration date we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the series C notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the series C notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

NOTICE TO CANADIAN RESIDENTS

Any resale of the series C notes in Canada must be made under applicable securities laws which will vary depending on the relevant jurisdiction, and which may require resales to be made under

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available statutory exemptions or under a discretionary exemption granted by the applicable Canadian securities regulatory authority. Note holders resident in Canada are advised to seek legal advice prior to any resale of the series C notes.

LEGAL MATTERS

Certain legal matters with respect to the series C exchange notes will be passed upon for us by Willkie Farr & Gallagher, New York, New York.

EXPERTS

The consolidated balance sheets of MidAmerican Energy Holdings Company (successor to MidAmerican Energy Holdings Company (Predecessor), or MEHC (Predecessor)), and its subsidiaries, which are herein collectively referred to as MEHC, as of December 31, 2002 and 2001 for MEHC, and the related consolidated statements of operations, stockholders' equity, and cash flows for the years ended December 31, 2002 and 2001 for MEHC, for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor) and for the period March 14, 2000 to December 31, 2000 for MEHC, included in this prospectus, and the related financial statement schedules included elsewhere in the registration statement, have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing herein (which report expresses an unqualified opinion and includes an explanatory paragraph referring to MEHC's change in its accounting policy for goodwill and other intangible assets in 2002 and for major maintenance, overhaul, and well workover costs in 2001), and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

With respect to the unaudited interim financial information for the periods ended March 31, 2003 and 2002, which is included in this prospectus, Deloitte & Touche LLP have applied limited procedures in accordance with professional standards for a review of such information. However, as stated in their report included herein, they did not audit and they do not express an opinion on that interim financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. Deloitte & Touche LLP are not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited interim financial information because this report is not a "report" or a "part" of the registration statement prepared or certified by an accountant within the meaning of Sections 7 and 11 of the Act.

WHERE YOU CAN FIND MORE INFORMATION

We file reports and information statements and other information with the SEC. Such reports, proxy and information statements and other information filed by us with the SEC can be inspected and copied at the Public Reference Section of the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, and at the regional offices of the SEC located at Woolworth Building, 233 Broadway, New York, New York 10279 and 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of such material can be obtained from the Public Reference Section of the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549 at prescribed rates. The SEC maintains a Web site that contains reports, proxy and information statements and other materials that are filed through the SEC's Electronic Data Gathering, Analysis, and Retrieval (EDGAR) system. This Web site can be accessed at http://www.sec.gov.

We make available free of charge through our internet website at http://www.midamerican.com our annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably practicable after we electronically file with, or furnish it to, the SEC. Any information available on or through our website is not part of this prospectus and our web address is included as an inactive textual reference only.

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FINANCIAL STATEMENTS

Index to Financial Statements


  Page
Independent Accountant's Report   F-2  
Consolidated Balance Sheets as of March 31, 2003 (unaudited) and December 31, 2002   F-3  
Consolidated Statements of Operations for the three-month periods ended March 31, 2003 and 2002 (unaudited)   F-4  
Consolidated Statements of Cash Flows for the three-month periods ended March 31, 2003 and 2002 (unaudited)   F-5  
Notes to Consolidated Financial Statements (unaudited)   F-6  
Independent Auditors' Report   F-16  
Consolidated Balance Sheets as of December 31, 2002 and 2001   F-17  
Consolidated Statements of Operations for the years ended December 31, 2002 and 2001 and for the periods from March 14, 2000 through December 31, 2000 and January 1, 2000 through March 13, 2000   F-18  
Consolidated Statements of Stockholders' Equity for the three years ended December 31, 2002, 2001 and 2000   F-19  
Consolidated Statements of Cash Flows for the years ended December 31, 2002 and 2001 and for the periods from March 14, 2000 through December 31, 2000 and January 1, 2000 through March 13, 2000   F-20  
Notes to Consolidated Financial Statements   F-21  

F-1

INDEPENDENT ACCOUNTANTS' REPORT

Board of Directors and Stockholders
MidAmerican Energy Holdings Company
Des Moines, Iowa

We have reviewed the accompanying consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries (the "Company") as of March 31, 2003, and the related consolidated statements of operations and cash flows for the three-month periods ended March 31, 2003 and 2002. These financial statements are the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to such financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries as of December 31, 2002, and the related consolidated statements of operations, stockholders' equity and cash flows for the year then ended (not presented herein); and in our report dated January 24, 2003, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP
    
DELOITTE & TOUCHE LLP
Des Moines, Iowa
May 8, 2003

F-2

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands)


  As of
  March 31,
2003		 December 31,
2002
  (Unaudited)
ASSETS
Current assets:
Cash and cash equivalents $ 852,868   $ 844,430  
Restricted cash and short-term investments   72,695     50,808  
Accounts receivable, net   734,901     707,731  
Inventories   62,326     126,938  
Other current assets   238,454     212,888  
Total current assets   1,961,244     1,942,795  
Properties, plants and equipment, net   10,135,056     9,898,796  
Excess of cost over fair value of net assets acquired   4,259,574     4,258,132  
Regulatory assets, net   568,882     415,804  
Other investments   444,679     446,732  
Equity investments   278,755     273,707  
Deferred charges and other assets   760,770     780,489  
Total assets $ 18,408,960   $ 18,016,455  
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 418,367   $ 462,960  
Accrued interest   182,348     192,015  
Accrued taxes   93,622     75,097  
Other accrued liabilities   518,838     457,058  
Short-term debt   70,932     79,782  
Current portion of long-term debt   364,358     470,213  
Total current liabilities   1,648,465     1,737,125  
Other long-term accrued liabilities   1,275,554     1,100,917  
Parent company debt   2,325,756     2,324,456  
Subsidiary and project debt   7,231,794     7,077,087  
Deferred income taxes   1,284,195     1,238,421  
Total liabilities   13,765,764     13,478,006  
Deferred income   77,695     80,078  
Minority interest   6,533     7,351  
Company-obligated mandatorily redeemable preferred securities of subsidiary trusts   2,063,935     2,063,412  
Preferred securities of subsidiaries   93,028     93,325  
Commitments and contingencies (Note 6)
Stockholders' equity:
Zero-coupon convertible preferred stock — authorized 50,000 shares, no par value, 41,263 shares outstanding   —     —  
Common stock — authorized 60,000 shares, no par value, 9,281 shares issued and outstanding   —     —  
Additional paid-in capital   1,956,509     1,956,509  
Retained earnings   714,645     584,009  
Accumulated other comprehensive loss   (269,149 )    (246,235 ) 
Total stockholders' equity   2,402,005     2,294,283  
Total liabilities and stockholders' equity $ 18,408,960   $ 18,016,455  

The accompanying notes are an integral part of these financial statements.

F-3

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)


  Three Months
Ended March 31,
  2003 2002
  (Unaudited)
Revenue:
Operating revenue $ 1,562,834   $ 1,041,752  
Income on equity investments   7,455     14,120  
Interest and dividend income   13,871     8,355  
Other income   19,794     5,350  
Total revenue   1,603,954     1,069,577  
Costs and expenses:
Cost of sales   672,750     409,283  
Operating expense   356,493     279,667  
Depreciation and amortization   141,849     126,244  
Interest expense   186,845     141,300  
Capitalized interest   (15,532 )    (6,647 ) 
Total costs and expenses   1,342,405     949,847  
Income before provision for income taxes   261,549     119,730  
Provision for income taxes   73,000     29,130  
Income before minority interest and preferred dividends   188,549     90,600  
Minority interest and preferred dividends   57,913     25,851  
Net income available to common and preferred stockholders $ 130,636   $ 64,749  

The accompanying notes are an integral part of these financial statements.

F-4

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)


  Three Months
Ended March 31,
  2003 2002
  (Unaudited)
Cash flows from operating activities:
Net income $ 130,636   $ 64,749  
Adjustments to reconcile net cash flows from operating activities:
Income in excess of distributions on equity investments   (3,541 )    (11,745 ) 
Depreciation and amortization   141,849     126,244  
Amortization of deferred financing costs   9,555     9,005  
Amortization of regulatory assets and liabilities and other   (9,709 )    (1,656 ) 
Provision for deferred income taxes   58,923     4,797  
Changes in other items:
Accounts receivable, net   (20,651 )    (137,731 ) 
Other current assets   53,018     54,595  
Accounts payable and other accrued liabilities   14,896     44,164  
Accrued interest   (9,357 )    28,551  
Accrued taxes   15,291     (15,560 ) 
Deferred income   (2,214 )    (492 ) 
Other   7,097     17,701  
Net cash flows from operating activities   385,793     182,622  
Cash flows from investing activities:
Acquisitions, net of cash acquired   (36,575 )    (493,696 ) 
Purchase of convertible preferred securities   —     (275,000 ) 
Capital expenditures relating to operating projects   (133,845 )    (95,673 ) 
Construction and other development costs   (244,033 )    (22,372 ) 
(Increase) decrease in restricted cash and investments   (603 )    5,423  
Other   (28,944 )    (5,372 ) 
Net cash flows from investing activities   (444,000 )    (886,690 ) 
Cash flows from financing activities:
Proceeds from subsidiary and project debt   287,572     395,428  
Proceeds from parent company debt   —     120,500  
Repayments of subsidiary and project debt   (211,268 )    (11,092 ) 
Net repayment of subsidiary short-term debt   (8,850 )    (46,195 ) 
Proceeds from issuance of trust preferred securities   —     323,000  
Proceeds from issuance of common and preferred stock   —     402,000  
Redemption of preferred securities of subsidiaries   (294 )    (100,320 ) 
Increase in restricted cash   (21,887 )    (23,012 ) 
Other   28,276     (31,113 ) 
Net cash flows from financing activities   73,549     1,029,196  
Effect of exchange rate changes   (6,904 )    (6,394 ) 
Net increase in cash and cash equivalents   8,438     318,734  
Cash and cash equivalents at beginning of period   844,430     386,745  
Cash and cash equivalents at end of period $ 852,868   $ 705,479  
Supplemental Disclosure:
Interest paid, net of interest capitalized $ 172,181   $ 146,222  
Income taxes paid $ 280   $ 20,167  

The accompanying notes are an integral part of these financial statements.

F-5

MIDAMERICAN ENERGY HOLDINGS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.    General

In the opinion of management of MidAmerican Energy Holdings Company and subsidiaries ("MEHC" or the "Company"), the accompanying unaudited consolidated financial statements contain all adjustments (consisting of normal recurring accruals) necessary to present fairly the financial position as of March 31, 2003, and the results of operations and cash flows for the three-month periods ended March 31, 2003 and 2002. The results of operations for the three-month period ended March 31, 2003 are not necessarily indicative of the results to be expected for the full year.

The unaudited consolidated financial statements include the accounts of MidAmerican Energy Holdings Company and its wholly and majority owned subsidiaries. Other investments and corporate joint ventures, where the Company has the ability to exercise significant influence, are accounted for under the equity method. Investments where the Company's ability to influence is limited are accounted for under the cost method of accounting.

Certain amounts in the prior year financial statements and supporting note disclosures have been reclassified to conform to the current year presentation. Such reclassification did not impact previously reported net income or retained earnings.

The unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

2.    New Accounting Pronouncements

Effective January 1, 2003 the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. The cumulative effect of initially applying this statement was immaterial.

The Company's review of its regulated entities identified legal retirement obligations for nuclear decommissioning, wet and dry ash landfills and offshore and minor lateral pipeline facilities. On January 1, 2003, the Company recorded $289.3 million of asset retirement obligation ("ARO") liabilities; $13.9 million of ARO assets, net of accumulated depreciation; $114.6 million of regulatory assets; and reclassified $1.0 million of accumulated depreciation to the ARO liability. The initial ARO liability recognized includes $266.5 million that pertains to obligations associated with the decommissioning of the Quad Cities nuclear station. The $266.5 million includes a $159.8 million nuclear decommissioning liability that had been recorded at December 31, 2002. The adoption of this statement did not have a material impact on the operations of the regulated entities, as the effects were offset by the establishment of regulatory assets, totaling $114.6 million, pursuant to SFAS No. 71.

During the three-month period ended March 31, 2003, the Company recorded, as a regulatory asset, accretion related to the ARO liability of $4.2 million resulting in an ARO liability balance of $293.5 million at March 31, 2003.

On April 30, 2003, the Financial Accounting Standards Board issued Statement No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" ("SFAS 149"). SFAS 149 amends SFAS No. 133 for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. SFAS 149 also amends certain other existing pronouncements. It will require contracts with comparable characteristics to be accounted for similarly. In particular, SFAS 149 clarifies when a contract with an initial net investment meets the characteristic of a derivative and clarifies when a derivative that contains a financing component will require special reporting in the statement of cash flows. SFAS 149 is effective for the Company for contracts entered into or modified after June 30, 2003. The Company and its subsidiaries are evaluating the impact of adopting the requirements of SFAS 149.

F-6

3.    Properties, Plants and Equipment, Net

Properties, plants and equipment, net comprise the following (in thousands):


  March 31,
2003		 December 31,
2002
Properties, plants and equipment, net:
Utility generation and distribution system $ 8,226,590   $ 8,165,140  
Interstate pipelines' assets   2,291,482     2,260,145  
Independent power plants   1,415,538     1,410,170  
Mineral and gas reserves and exploration assets   508,062     500,422  
Utility non-operational assets   381,269     370,811  
Other assets   136,343     131,577  
Total operating assets   12,959,284     12,838,265  
Accumulated depreciation and amortization   (4,261,446 )    (4,109,954 ) 
Net operating assets   8,697,838     8,728,311  
Construction in progress   1,437,218     1,170,485  
Properties, plants and equipment, net $ 10,135,056   $ 9,898,796  

Construction in Progress

Kern River Gas Transmission Company ("Kern River") completed the construction of its 2003 Expansion Project at a total cost of approximately $1.2 billion. The expansion, which was placed into operation on May 1, 2003, increased the design capacity of the existing Kern River pipeline by 885,626 decatherms per day to 1,755,626 decatherms per day.

4.    Investment in CE Generation

The equity investment in CE Generation LLC ("CE Generation") at March 31, 2003 and December 31, 2002 was approximately $247.4 million and $244.9 million, respectively. During the three-month period ended March 31, 2003 and 2002, the Company recorded income from its investment in CE Generation of $2.3 million and $7.2 million, respectively.

5.    Debt Issuances and Redemptions

On January 14, 2003, MidAmerican Energy Company ("MidAmerican Energy") issued $275.0 million of 5.125% medium-term notes due in 2013. The proceeds were used to refinance existing debt and for other corporate purposes.

On May 1, 2003, Kern River Funding Corporation, a wholly owned subsidiary of Kern River, issued $836 million of its 4.893% Senior Notes with a final maturity on April 30, 2018. The proceeds were used to repay all of the approximately $815 million of outstanding borrowings under Kern River's $875 million credit facility. Kern River entered into this credit facility in 2002 to finance the construction of the 2003 Expansion Project. The credit facility was canceled and a completion guarantee issued by the Company in favor of the lenders as part of the credit facility terminated upon completion of the 2003 Expansion Project.

On April 23, 2003, Yorkshire Power Group Limited, a wholly owned subsidiary of MEHC, reported that it had authorized the redemption in full of the outstanding shares of the Yorkshire Capital Trust I, 8.08% Trust Securities, due June 30, 2038. The Trust Securities will be redeemed on June 9, 2003, at a redemption price of 100% of the principal amount ($25 liquidation amount per each Trust Security) plus accrued distributions of $0.381555555 per Trust Security to the redemption date. The redemption price will be paid to holders of the Trust Security on the redemption date. At March 31, 2003 and December 31, 2002, $250.5 million and $249.7 million, respectively, of the Trust Securities are included in subsidiary and project debt.

F-7

6.    Commitments and Contingencies

Manufactured Gas Plants

The United States Environmental Protection Agency ("EPA") and the state environmental agencies have determined that contaminated wastes remaining at decommissioned manufactured gas plant facilities may pose a threat to the public health or the environment if such contaminants are in sufficient quantities and at such concentrations as to warrant remedial action.

MidAmerican Energy has evaluated or is evaluating 27 properties that were, at one time, sites of gas manufacturing plants in which it may be a potentially responsible party. The purpose of these evaluations is to determine whether waste materials are present, whether the materials constitute an environmental or health risk, and whether MidAmerican Energy has any responsibility for remedial action. MidAmerican Energy is currently conducting field investigations at 21 sites, has conducted interim removal actions at 14 sites and has received regulatory closure on two sites. MidAmerican Energy is continuing to evaluate several of the sites to determine the future liability, if any, for conducting site investigations or other site activity.

MidAmerican Energy estimates the range of possible costs for investigation, remediation and monitoring for the sites discussed above to be $16 million to $54 million. As of March 31, 2003, MidAmerican Energy has recorded a $21 million liability for these sites and a corresponding regulatory asset for future recovery through the regulatory process. MidAmerican Energy projects that these amounts will be paid or incurred over the next four years.

The estimate of probable remediation costs is established on a site-specific basis. The costs are accumulated in a three-step process. First, a determination is made as to whether MidAmerican Energy has potential legal liability for the site and whether information exists to indicate that contaminated wastes remain at the site. If so, the costs of performing a preliminary investigation and the costs of removing known contaminated soil are accrued. As the investigation is performed and if it is determined remedial action is required, the best estimate of remedial costs is accrued. The estimated recorded liabilities for these properties include incremental direct costs of the remediation effort, costs for future monitoring at sites and costs of compensation to employees for time expected to be spent directly on the remediation effort. The estimated recorded liabilities for these properties are based upon preliminary data. Thus, actual costs could vary significantly from the estimates. The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action and changes in technology relating to remedial alternatives. Insurance recoveries have been received for some of the sites under investigation. Those recoveries are intended to be used principally for accelerated remediation, as specified by the Iowa Utilities Board ("IUB"), and are recorded as a regulatory liability.

Although the timing of potential incurred costs and recovery of such costs in rates may affect the results of operations in individual periods, management believes that the outcome of these issues will not have a material adverse effect on MidAmerican Energy's financial position or results of operations.

Air Quality

In July 1997, the EPA adopted revisions to the National Ambient Air Quality Standards for ozone and a new standard for fine particulate matter. Based on data to be obtained from monitors located throughout each state, the EPA will determine which states have areas that do not meet the air quality standards (i.e., areas that are classified as nonattainment). The standards were subjected to legal proceedings, and in February 2001, the United States Supreme Court upheld the constitutionality of the standards, though remanding the issue of implementation of the ozone standard to the EPA. As a result of a decision rendered by the United States Circuit Court of Appeals for the District of Columbia, the EPA is moving forward in implementation of the ozone and fine particulate standards and is analyzing existing monitored data to determine attainment status.

The impact of the new standards on MidAmerican Energy is currently unknown. MidAmerican Energy's generating stations may be subject to emission reductions if the stations are located in

F-8

nonattainment areas or contribute to nonattainment areas in other states. As part of state implementation plans to achieve attainment of the standards, MidAmerican Energy could be required to install control equipment on its generating stations or decrease the number of hours during which these stations operate.

The ozone and fine particulate matter standards could, in whole or in part, be superceded by one of a number of multi-pollutant emission reduction proposals currently under consideration at the federal level. In July 2002, legislation was introduced in Congress to implement the Administration's "Clear Skies Initiative," calling for reduction in emissions of sulfur dioxide, nitrogen oxides and mercury through a cap-and-trade system. Reductions would begin in 2008 with additional emission reductions being phased in through 2018.

While legislative action is necessary for the Clear Skies Initiative or other multi-pollutant emission reduction initiatives to become effective, MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions required to meet emissions reductions of this nature. On April 1, 2002, in accordance with Iowa law passed in 2001, MidAmerican Energy filed with the IUB its first multi-year plan and budget for managing regulated emissions from its generating facilities in a cost-effective manner. MidAmerican Energy expects the IUB to rule on the prudence of the multi-year plan and budget in 2003.

In recent years, the EPA has requested from several utilities information and support regarding their capital projects for various generating plants. The requests were issued as part of an industry-wide investigation to assess compliance with the New Source Review and the New Source Performance Standards of the Clean Air Act. In December 2002, MidAmerican Energy received a request from the EPA to provide documentation related to its capital projects from January 1, 1980, to the present for its Neal, Council Bluffs, Louisa and Riverside Energy Centers. MidAmerican Energy has responded to this request and at this time cannot predict the outcome of this request.

Nuclear Decommissioning Costs

Each licensee of a nuclear facility is required to provide financial assurance for the cost of decommissioning its licensed nuclear facility. In general, decommissioning of a nuclear facility means to safely remove the facility from service and restore the property to a condition allowing unrestricted use by the operator.

Based on information presently available, MidAmerican Energy expects to contribute approximately $41 million during the period 2003 through 2007 to external trusts established for the investment of funds for decommissioning Quad Cities Station. Approximately 60% of the fair value of the trusts' funds is now invested in domestic corporate debt and common equity securities. The remainder is invested in investment grade municipal and U.S. Treasury bonds. Funding for Quad Cities Station nuclear decommissioning is reflected as depreciation expense in the Consolidated Statements of Income. Quad Cities Station decommissioning costs charged to Iowa customers are included in base rates, and recovery of increases in those amounts must be sought through the normal ratemaking process.

Pipeline Litigation

In 1998, the United States Department of Justice informed the then current owners of Kern River and Northern Natural Gas Company ("Northern Natural Gas") that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against such entities and certain of their subsidiaries including Kern River and Northern Natural Gas. Mr. Grynberg has also filed claims against numerous other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties allegedly not paid to the federal government, treble damages, civil penalties, attorneys' fees and costs. On April 9, 1999, the United States Department of Justice announced that it declined to intervene in any of the Grynberg qui tam cases, including the actions filed against Kern River and Northern Natural Gas in the United States District Court for the District of Colorado. On October 21, 1999, the Panel on Multi-District

F-9

Litigation transferred the Grynberg qui tam cases, including the ones filed against Kern River and Northern Natural Gas, to the United States District Court for the District of Wyoming for pre-trial purposes. Motions to dismiss the complaint, filed by various defendants including Northern Natural Gas and The Williams Companies, Inc. ("Williams") which was the former owner of Kern River, were denied on May 18, 2001. On October 9, 2002, the United States District Court for the District of Wyoming dismissed Grynberg's Royalty Valuation Claims. On November 19, 2002, the Court denied Grynberg's motion for clarification dismissing royalty valuation claims. Grynberg has appealed this dismissal to the United States Court of Appeals for the Tenth Circuit. In connection with the purchase of Kern River from Williams in March 2002, Williams agreed to indemnify the Company against any liability for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. No such indemnification was obtained in connection with the purchase of Northern Natural Gas in August 2002. The Company believes that the Grynberg cases filed against Kern River and Northern Natural Gas are without merit and Williams, on behalf of Kern River pursuant to its indemnification, and Northern Natural Gas, intend to defend these actions vigorously.

On June 8, 2001, a number of interstate pipeline companies, including Kern River and Northern Natural Gas, were named as defendants in a nationwide class action lawsuit which had been pending in the 26th Judicial District, District Court, Stevens County Kansas, Civil Department against other defendants, generally pipeline and gathering companies, since May 20, 1999. The plaintiffs allege that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs. In November 2001, Kern River and Northern Natural Gas, along with the coordinating defendants, filed a motion to dismiss under Rules 9B and 12B of the Kansas Rules of Civil Procedure. In January 2002, Kern River and most of the coordinating defendants filed a motion to dismiss for lack of personal jurisdiction. The court has yet to rule on these motions. The plaintiffs filed for certification of the plaintiff class on September 16, 2002. On January 13, 2003, oral arguments were heard on coordinating defendants' opposition to class certification. On April 10, 2003, the court entered an order denying the plaintiffs' motion for class certification. It is anticipated that the plaintiffs will appeal this decision. On April 10, 2003, the court entered an order denying the plaintiffs' motion for class certification. It is anticipated that the plaintiffs will appeal this decision. Williams has agreed to indemnify the Company against any liability associated with Kern River for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. Williams, on behalf of Kern River and other entities, anticipates joining with Northern Natural Gas and other defendants in contesting certification of the plaintiff class. Kern River and Northern Natural Gas believe that this claim is without merit and that Kern River's and Northern Natural Gas' gas measurement techniques have been in accordance with industry standards and its tariff.

Philippines

Casecnan Construction Contract

The CE Casecnan Water and Energy Company, Inc. ("CE Casecnan") Project (the "Casecnan Project") was initially constructed pursuant to a fixed-price, date-certain, turnkey construction contract (the "Hanbo Contract") on a joint and several basis by Hanbo Corporation ("Hanbo") and Hanbo Engineering and Construction Co., Ltd. ("HECC"), both of which are South Korean corporations. On May 7, 1997, CE Casecnan terminated the Hanbo Contract due to defaults by Hanbo and HECC including the insolvency of both companies. On the same date, CE Casecnan entered into a new fixed-price, date certain, turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Replacement Contract"). The work under the Replacement Contract was conducted by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa., (collectively, the "Contractor"), working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd.

On November 20, 1999, the Replacement Contract was amended to extend the Guaranteed Substantial Completion Date for the Casecnan Project to March 31, 2001. This amendment was approved by the lenders' independent engineer under the Trust Indenture.

F-10

On February 12, 2001, the Contractor filed a Request for Arbitration with the International Chamber of Commerce ("ICC") seeking schedule relief of up to 153 days through August 31, 2001 resulting from various alleged force majeure events. In its March 20, 2001 Supplement to Request for Arbitration, the Contractor also seeks compensation for alleged additional costs of approximately $4 million it incurred from the claimed force majeure events to the extent it is unable to recover from its insurer. On April 20, 2001, the Contractor filed a further supplement seeking an additional compensation for damages of approximately $62 million for the alleged force majeure event (and geologic conditions) related to the collapse of the surge shaft. The Contractor has alleged that the circumstances surrounding the placing of the Casecnan Project into commercial operation in December 2001 amounted to a repudiation of the Replacement Contract and has filed a claim for unspecified quantum meruit damages, and has further alleged that the delay liquidated damages clause which provides for payments of $125,000 per day for each day of delay in completion of the Casecnan Project for which the Contractor is responsible is unenforceable. The arbitration is being conducted applying New York law and pursuant to the rules of the ICC.

Hearings have been held in connection with this arbitration in July 2001, September 2001, January 2002, March 2002, November 2002 and January 2003. As part of those hearings, on June 25, 2001, the arbitration tribunal temporarily enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di Roma in support of the Contractor's obligations to CE Casecnan for delay liquidated damages. As a result of the continuing nature of that injunction, on April 26, 2002, CE Casecnan and the Contractor mutually agreed that no demands would be made on the Banca di Roma demand guaranty except pursuant to an arbitration award. As of March 31, 2003, however, CE Casecnan has received approximately $6.0 million of liquidated damages from demands made on the demand guarantees posted by Commerzbank on behalf of the Contractor. On November 7, 2002, the ICC issued the arbitration tribunal's partial award with respect to the Contractor's force majeure and geologic conditions claims. The arbitration panel awarded the Contractor 18 days of schedule relief in the aggregate for all of the force majeure events and awarded the Contractor $3.8 million with respect to the cost of the collapsed surge shaft. The $3.8 million is shown as part of the accounts payable and accrued expenses balance at March 31, 2003 and December 31, 2002. All of the Contractor's other claims with respect to force majeure and geologic conditions were denied.

Further hearings on the Contractor's repudiation and quantum meruit claims, the alleged unenforceability of the delay liquidated damages clause and certain other matters had been scheduled for March 24 through March 28, 2003, but were postponed as a result of the commencement of military action in Iraq. The hearings have been rescheduled for June 30 through July 11, 2003.

If the Contractor were to prevail on its claim that the delay liquidated damages clause is unenforceable, CE Casecnan would not be entitled to collect such delay damages for the period from March 31, 2001 through December 11, 2001. If the Contractor were to prevail in its repudiation claim and prove quantum meruit damages in excess of amounts paid to the Contractor, CE Casecnan could be liable to make additional payments to the Contractor. CE Casecnan believes all of such allegations and claims are without merit and is vigorously contesting the Contractor's claims.

Casecnan NIA Arbitration

Under the terms of the Project Agreement, the Philippines National Irrigation Administration ("NIA") has the option of timely reimbursing CE Casecnan directly for certain taxes CE Casecnan has paid. If NIA does not so reimburse CE Casecnan, the taxes paid by CE Casecnan result in an increase in the Water Delivery Fee. The payment of certain other taxes by CE Casecnan results automatically in an increase in the Water Delivery Fee. As of March 31, 2003, CE Casecnan has paid approximately $58.1 million in taxes, which as a result of the foregoing provisions results in an increase in the Water Delivery Fee. NIA has failed to pay the portion of the Water Delivery Fee each month, related to the payment of these taxes by CE Casecnan. As a result of this non-payment, on August 19, 2002, CE Casecnan filed a Request for Arbitration against NIA, seeking payment of such portion of the Water Delivery Fee and enforcement of the relevant provision of the Project Agreement going forward. The arbitration will be conducted in accordance with the rules of the ICC.

F-11

NIA filed its Answer and Counterclaim on March 31, 2003. In its Answer, NIA asserts, among other things, that most of the taxes which CE Casecnan has factored into the Water Delivery Fee compensation formula do not fall within the scope of the relevant section of the Project Agreement, that the compensation mechanism itself is invalid and unenforceable under Philippine law and that the Project Agreement is inconsistent with the Philippine build-operate-transfer ("BOT") law. As such, NIA seeks dismissal of CE Casecnan's claims and a declaration from the arbitral tribunal that the taxes which have been taken into account in the Water Delivery Fee compensation mechanism are not recoverable thereunder and that, at most, certain taxes may be directly reimbursed (rather than compensated for through the Water Delivery Fee) by NIA. NIA also counterclaims for approximately $7 million which it alleges is due to it as a result of the delayed completion of the Casecnan Project. On April 23, 2003, NIA filed a Supplemental Counterclaim in which it asserts that the Project Agreement is contrary to Philippine law and public policy and by way of relief seeks a declaration that the Project Agreement is void from the beginning or should be cancelled, or alternatively, an order for reformation of the Project Agreement or any portions or sections thereof which may be determined to be contrary to such law and or public policy. CE Casecnan intends to vigorously contest all of NIA's assertions and counterclaims.

The three member arbitration panel has been confirmed by the ICC and an initial organizational hearing was held on April 28, 2003. Hearings on this matter are scheduled for July 2004.

Included in revenue, for the three months ended March 31, 2003 and 2002, were $5.5 million and $5.8 million, respectively, of tax compensation for Water Delivery Fees under the Project Agreement, none of which has been paid. As of March 31, 2003 and December 31, 2002, the net receivable for the tax compensation piece of the Water Delivery Fees invoiced since the start of commercial operations totaled $29.8 million and $24.3 million, respectively.

Casecnan Stockholder Litigation

Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro forma financial projections of the Casecnan Project prepared following commencement of commercial operations, in February 2002, MEHC, through its indirect wholly owned subsidiary CE Casecnan Ltd., advised the minority stockholder LaPrairie Group Contractors (International) Ltd., ("LPG"), that MEHC's indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against, inter alia, CE Casecnan Ltd. and MEHC. In the complaint, LPG seeks compensatory and punitive damages for alleged breaches of the stockholder agreement and alleged breaches of fiduciary duties allegedly owed by CE Casecnan Ltd. and MEHC to LPG. The complaint also seeks injunctive relief against all defendants and a declaratory judgment that LPG is entitled to maintain its 15% interest in CE Casecnan. The impact, if any, of this litigation on CE Casecnan cannot be determined at this time.

In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. ("San Lorenzo"), an original shareholder substantially all of whose shares in CE Casecnan MEHC purchased in 1998, threatened to initiate legal action in the Philippines in connection with certain aspects of its option to repurchase such shares on or prior to commercial operation of the Casecnan Project. CE Casecnan believes that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, will vigorously defend any such action.

Philippine Political Risks

In connection with an interagency review of approximately 40 independent power project contracts in the Philippines, the Casecnan Project (together with four other unrelated projects) has reportedly been identified as raising legal and financial questions and, with those projects, has been prioritized for renegotiation. The Company's subsidiaries' Upper Mahiao, Malitbog, and Mahanagdong projects have also reportedly been identified as raising financial questions. No written report has yet been issued with respect to the interagency review, and the timing and nature of steps, if any that the

F-12

Philippine Government may take in this regard are not known. Accordingly, it is not known what, if any, impact the government's review will have on the operations of the Company's Philippine Projects. CE Casecnan representatives, together with certain current and former government officials, also have been requested to appear, and have appeared during 2002, before a Philippine Senate committee which has raised questions and made allegations with respect to the Casecnan Project's tariff structure and implementation.

On May 5, 2003, the Philippine Supreme Court issued its ruling in a case involving an unsolicited BOT project for the development, construction and operation of the new Manila International Airport. Various members of Congress and labor unions initiated the action in the Philippine Supreme Court on September 17, 2002 seeking to enjoin the enforcement of the BOT agreement with an international consortium known as PIATCO (the "PIATCO Agreement"). The PIATCO Consortium is unrelated to CE Casecnan or the Company. On March 4, 2003, PIATCO separately initiated an ICC arbitration pursuant to the terms of the PIATCO Agreement. The Supreme Court, in its ruling, stated that there were no unresolved factual issues and therefore it had original jurisdiction and concluded that the pendency of the arbitration did not preclude the court from ruling on a case brought by non-parties to the PIATCO Agreement, such as members of the Philippine Congress or non-governmental organizations. In a public speech on November 29, 2002 prior to the December 10, 2002 oral arguments before the Philippine Supreme Court, Philippine President Arroyo stated that she would not honor the PIATCO Agreement because the executive branch's legal department had concluded it was "null and void". In light of that announcement, the project owners stopped work on the project, which is approximately 90% complete and accordingly has not been placed into commercial operation. In its 10 to 3 ruling (with one abstention) issued on May 5, 2003, the Philippine Supreme Court ruled that the PIATCO Agreement was contrary to Philippine law and public policy and was "null and void". CE Casecnan is assessing the impact of the PIATCO ruling on the Casecnan Project.

On April 24, 2003 Standard & Poor's Ratings Services ("S&P") lowered its rating of CE Casecnan to 'BB' from 'BB+' as a result of S&P's downgrade of the Republic of the Philippines. The downgrade of the Philippines by S&P reflected the Country's growing debt burden and fiscal rigidity.

On May 8, 2003, Moody's Investors Service ("Moody's") placed the Ba2 senior secured notes rating of CE Casecnan on review for possible downgrade, noting NIA's supplemental counterclaim seeking to have the Project Agreement declared void. Moody's noted that actions by government related agencies and the resulting instability of contractual arrangements was becoming inconsistent with their rating approach that attaches significant benefit to offtake arrangements with those government supported entities.

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7.    Comprehensive Income

The differences from net income to total comprehensive income for the Company are due to minimum pension liability adjustments, foreign currency translation adjustments, unrealized holding gains and losses of marketable securities during the periods, and the effective portion of net gains and losses of derivative instruments classified as cash flow hedges. Total comprehensive income for the Company is shown in the table below (in thousands).


  Three Months
Ended March 31,
  2003 2002
Net income $ 130,636   $ 64,749  
Other comprehensive income:
Minimum pension liability adjustment, net of tax of $927   2,164     —  
Foreign currency translation   (30,171 )    (28,515 ) 
Marketable securities, net of tax of $(83) and $(1,116), respectively   (133 )    (2,158 ) 
Cash flow hedges, net of tax of $2,442 and $3,803, respectively   5,226     9,819  
Total comprehensive income $ 107,722   $ 43,895  

8.    Segment Information

The Company has identified seven reportable operating segments based on management structure: MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK Funding, Inc. ("CE Electric UK"), CalEnergy Generation-Domestic, CalEnergy Generation-Foreign, and HomeServices of America, Inc. ("HomeServices"). Information related to the Company's reportable operating segments is shown below (in thousands).


  Three Months
Ended March 31,
  2003 2002
Operating revenue:
MidAmerican Energy $ 815,916   $ 575,035  
Kern River   39,030     2,198  
Northern Natural Gas   170,002     —  
CE Electric UK   225,532     213,957  
CalEnergy Generation – Domestic   11,233     5,105  
CalEnergy Generation – Foreign   76,729     74,085  
HomeServices   257,988     174,566  
Segment operating revenue   1,596,430     1,044,946  
Corporate/other   (33,596 )    (3,194 ) 
Total operating revenue $ 1,562,834   $ 1,041,752  
Income (loss) before provision for income taxes:
MidAmerican Energy $ 89,892   $ 70,288  
Kern River   26,376     971  
Northern Natural Gas   83,639     —  
CE Electric UK   84,773     60,967  
CalEnergy Generation – Domestic   (5,858 )    (2,289 ) 
CalEnergy Generation – Foreign   34,532     30,693  
HomeServices   7,005     (129 ) 
Segment income before provision for income taxes   320,359     160,501  
Corporate/other   (58,810 )    (40,771 ) 
Total income before provision for income taxes $ 261,549   $ 119,730  

F-14


  March 31,
2003		 December 31,
2002
Total Assets:
MidAmerican Energy $ 6,327,397   $ 6,025,452  
Kern River   2,006,722     1,797,850  
Northern Natural Gas   2,307,055     2,162,367  
CE Electric UK   4,649,245     4,714,459  
CalEnergy Generation – Domestic   892,019     881,633  
CalEnergy Generation – Foreign   994,617     974,852  
HomeServices   543,701     488,324  
Segment total assets   17,720,756     17,044,937  
Corporate/other   688,204     971,518  
Total assets $ 18,408,960   $ 18,016,455  

The remaining differences from the segment amounts to the consolidated amounts described as "Corporate/other" relate principally to the corporate functions including administrative costs, corporate cash and related interest income, intersegment eliminations, and fair value adjustments relating to acquisitions. Total assets by segment includes the allocation of goodwill.

Excess of cost over fair value as of December 31, 2002 and changes for the period from January 1, 2003 through March 31, 2003 by segment are as follows (in thousands):


  MidAmerican
Energy		 Kern
River		 Northern
Natural
Gas		 CE Electric
UK		 CalEnergy
Generation-
Domestic		 Home-
Services		 Total
Goodwill at December 31, 2002 $ 2,149,282   $ 32,547   $ 414,721   $ 1,195,321   $ 126,440   $ 339,821   $ 4,258,132  
Acquisitions/purchase price accounting adjustments   —     1,353     (619 )    —     —     15,747     16,481  
Translation adjustment   —     —     —     (15,039 )    —     —     (15,039 ) 
Goodwill at March 31, 2003 $ 2,149,282   $ 33,900   $ 414,102   $ 1,180,282   $ 126,440   $ 355,568   $ 4,259,574  

F-15

INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholders
MidAmerican Energy Holdings Company
Des Moines, Iowa

We have audited the accompanying consolidated balance sheets of MidAmerican Energy Holdings Company (successor to MidAmerican Energy Holdings Company (Predecessor), referred to as "MEHC (Predecessor)") and subsidiaries (the "Company") as of December 31, 2002 and 2001 for the Company, and the related consolidated statements of operations, stockholders' equity, and cash flows for the years ended December 31, 2002 and 2001 for the Company, for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor), and for the period March 14, 2000 to December 31, 2000 for the Company. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of MidAmerican Energy Holdings Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for the above stated periods in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, in 2002 the Company changed its accounting policy for goodwill and other intangible assets and in 2001 the Company changed is accounting policy for major maintenance, overhaul and well workover costs.

/s/ Deloitte & Touche LLP

DELOITTE & TOUCHE LLP
Des Moines, Iowa
January 24, 2003

F-16

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands)


  As of December 31,
  2002 2001
ASSETS
Current assets:
Cash and cash equivalents $ 844,430   $ 386,745  
Restricted cash and short-term investments   50,808     30,565  
Accounts receivable, net of allowance for doubtful accounts of
$39,742 and $7,319 		  707,731     310,030  
Inventories   126,938     135,822  
Other current assets   212,888     106,124  
Total current assets   1,942,795     969,286  
Properties, plants and equipment, net   9,810,087     6,537,371  
Excess of cost over fair value of net assets acquired   4,258,132     3,638,546  
Regulatory assets   504,513     221,120  
Other investments   446,732     174,185  
Equity investments   273,707     261,432  
Deferred charges and other assets   780,489     824,712  
Total assets $ 18,016,455   $ 12,626,652  
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 462,960   $ 266,027  
Accrued interest   192,015     130,569  
Accrued taxes   75,097     88,973  
Other accrued liabilities   457,058     308,924  
Short-term debt   79,782     256,012  
Current portion of long-term debt   470,213     317,180  
Total current liabilities   1,737,125     1,367,685  
Other long-term accrued liabilities   1,100,917     537,495  
Parent company debt   2,324,456     1,834,498  
Subsidiary and project debt   7,077,087     4,754,811  
Deferred income taxes   1,238,421     1,284,268  
Total liabilities   13,478,006     9,778,757  
Deferred income   80,078     85,917  
Minority interest   7,351     44,477  
Company-obligated mandatorily redeemable preferred securities of subsidiary trusts   2,063,412     788,151  
Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts   —     100,000  
Preferred securities of subsidiaries   93,325     121,183  
Commitments and contingencies (Note 20)
Stockholders' equity:
Zero coupon convertible preferred stock – authorized 50,000 shares, no par value, 41,263 and 34,563 shares outstanding at December 31, 2002 and 2001, respectively   —     —  
Common stock — authorized 60,000 no par value; 9,281 shares issued and outstanding at December 31, 2002 and 2001   —     —  
Additional paid-in capital   1,956,509     1,553,073  
Retained earnings   584,009     223,926  
Accumulated other comprehensive loss, net   (246,235 )    (68,832 ) 
    Total stockholders' equity   2,294,283     1,708,167  
Total liabilities and stockholders' equity $ 18,016,455   $ 12,626,652  

The accompanying notes are an integral part of these financial statements.

F-17

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands)


  Year Ended December 31, March 14, 2000
through
December 31, 2000		 MEHC
(Predecessor)
January 1, 2000
through
March 13, 2000
  2002 2001
Revenue:
Operating revenue $ 4,794,010   $ 4,696,781   $ 3,918,100   $ 1,056,365  
Income on equity investments   40,520     39,565     40,019     3,497  
Interest and dividend income   56,250     24,552     25,320     8,080  
Other income   77,359     212,082     29,543     7,907  
Total revenue   4,968,139     4,972,980     4,012,982     1,075,849  
Costs and expenses:
Cost of sales   1,844,024     2,341,178     2,194,512     574,679  
Operating expense   1,345,205     1,176,422     904,511     226,908  
Depreciation and amortization   525,902     538,702     383,351     97,278  
Interest expense   647,379     499,263     396,773     101,330  
Less interest capitalized   (37,469 )    (86,469 )    (85,369 )    (15,516 ) 
Total costs and expenses   4,325,041     4,469,096     3,793,778     984,679  
Income before provision for income taxes   643,098     503,884     219,204     91,170  
Provision for income taxes   99,588     250,064     53,277     31,008  
Income before minority interest and preferred dividends   543,510     253,820     165,927     60,162  
Minority interest and preferred dividends   163,467     106,547     84,670     8,850  
Income before cumulative effect of change in accounting principle   380,043     147,273     81,257     51,312  
Cumulative effect of change in accounting principle, net of tax (Note 2)   —     (4,604 )    —     —  
Net income available to common and preferred stockholders $ 380,043   $ 142,669   $ 81,257   $ 51,312  

The accompanying notes are an integral part of these financial statements.

F-18

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Amounts in thousands)


  Outstanding
Common
Shares		 Common
Stock		 Additional
Paid-In
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Treasury
Stock		 Total
Balance, January 1, 2000   59,944   $     —   $ 1,249,079   $ 507,726   $ (12,029 )  $ (750,188 )  $ 994,588  
Net income January 1, 2000 through March 13, 2000   —     —     —     51,312     —     —     51,312  
Net income March 14, 2000 through December 31, 2000   —     —     —     81,257     —     —     81,257  
Other comprehensive income:
Foreign currency translation adjustment   —     —     —     —     (82,996 )    —     (82,996 ) 
Minimum pension liability adjustment, net of tax of $1,699   —     —     —     —     (2,388 )    —     (2,388 ) 
Unrealized gains on securities, net of tax of $1,164   —     —     —     —     2,160     —     2,160  
Total other comprehensive income                                       49,345  
Exercise of stock options and other equity transactions   13     —     (138 )    —     —     418     280  
Teton Transaction   (50,676 )    —     304,132     (559,038 )    37,324     749,770     532,188  
Balance, December 31, 2000   9,281     —     1,553,073     81,257     (57,929 )    —     1,576,401  
Net income   —     —     —     142,669     —     —     142,669  
Other comprehensive income:
Foreign currency translation adjustment   —     —     —     —     (22,103 )    —     (22,103 ) 
Fair value adjustment on cash flow hedges, net of tax of $8,143   —     —     —     —     18,490     —     18,490  
Minimum pension liability adjustment, net of tax of $3,448   —     —     —     —     (4,847 )    —     (4,847 ) 
Unrealized losses on securities, net of tax of $1,315   —     —     —     —     (2,443 )    —     (2,443 ) 
Total other comprehensive income                                       131,766  
Balance, December 31, 2001   9,281     —     1,553,073     223,926     (68,832 )    —     1,708,167  
Net income   —     —     —     380,043     —     —     380,043  
Other comprehensive income:
Foreign currency translation adjustment   —     —     —     —     166,880     —     166,880  
Fair value adjustment on cash flow hedges, net of tax of $10,106   —     —     —     —     (27,623 )    —     (27,623 ) 
Minimum pension liability adjustment, net of tax of $135,707   —     —     —     —     (313,456 )    —     (313,456 ) 
Unrealized losses on securities, net of tax of $1,813   —     —     —     —     (3,204 )    —     (3,204 ) 
Total other comprehensive income                                       202,640  
Issuance of zero-coupon convertible preferred stock   —     —     402,000     —     —     —     402,000  
Retirement of stock options   —     —     815     (19,960 )    —     —     (19,145 ) 
Other equity transactions   —     —     621     —     —     —     621  
Balance, December 31, 2002   9,281   $ —   $ 1,956,509   $ 584,009   $ (246,235 )  $ —   $ 2,294,283  

The accompanying notes are an integral part of these financial statements.

F-19

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)


  Year Ended December 31, March 14, 2000
through
December 31, 2000		 MEHC
(Predecessor)
January 1, 2000
through
March 13, 2000
  2002 2001
Cash flows from operating activities:
Net income $ 380,043   $ 142,669   $ 81,257   $ 51,312  
Adjustments to reconcile net cash flows from operating activities:
Income in excess of distributions on equity investments   (11,383 )    (28,515 )    (26,607 )    (3,459 ) 
Gains on non-recurring items   (25,329 )    (179,493 )    —     —  
Depreciation and amortization   525,902     442,284     303,354     83,097  
Amortization of excess of cost over fair value
of net assets acquired 		  —     96,418     79,997     14,181  
Amortization of deferred financing and
other costs 		  46,132     20,529     18,310     4,075  
Provision for deferred income taxes   (16,228 )    152,920     (15,460 )    7,735  
Cumulative effect of change in accounting principle, net of tax   —     4,604     —     —  
Changes in other items:
Accounts receivable, net   (244,829 )    639,868     (333,277 )    (11,769 ) 
Other current assets   42,552     (20,041 )    16,990     12,209  
Accounts payable and other accrued liabilities   36,083     (424,374 )    124,030     (21,242 ) 
Accrued interest   68,924     (1,683 )    (19,892 )    35,701  
Accrued taxes   (39,302 )    (4,616 )    7,238     (4,270 ) 
Deferred income   (4,839 )    6,428     10,467     3,513  
Net cash flows from operating activities   757,726     846,998     246,407     171,083  
Cash flows from investing activities:
Acquisitions, net of cash acquired   (1,416,937 )    (81,934 )    (2,048,266 )    —  
Purchase of convertible preferred securities   (275,000 )    —     —     —  
Capital expenditures relating to operating projects   (542,615 )    (398,165 )    (301,948 )    (44,355 ) 
Construction and other development costs   (965,470 )    (178,587 )    (236,781 )    (79,186 ) 
Proceeds from sale of assets   214,070     377,396     —     —  
Decrease in restricted cash and investments   16,351     24,540     157,905     48,788  
Other   61,790     18,206     39,930     19,879  
Net cash flows from investing activities   (2,907,811 )    (238,544 )    (2,389,160 )    (54,874 ) 
Cash flows from financing activities:
Proceeds from subsidiary and project debt   1,485,349     200,000     262,176     6,043  
Proceeds from parent company debt   700,000     —     —     —  
Repayments of subsidiary and project debt   (395,370 )    (437,372 )    (234,776 )    (3,135 ) 
Net proceeds from (repayment of) corporate revolver   (153,500 )    68,500     85,000     —  
Repayment of other obligations   (94,297 )    —     (4,225 )    —  
Net repayment of subsidiary short-term debt   (472,835 )    (74,144 )    (88,106 )    (124,761 ) 
Proceeds from issuance of trust preferred securities   1,273,000     —     454,772     —  
Proceeds from issuance of common and
preferred stock 		  402,000     —     1,428,024     —  
Redemption of preferred securities of subsidiaries   (127,908 )    (24,910 )    (20,409 )    —  
Other   (61,205 )    9,459     (3,607 )    (6,648 ) 
Net cash flows from financing activities   2,555,234     (258,467 )    1,878,849     (128,501 ) 
Effect of exchange rate changes   52,536     (1,394 )    (1,555 )    (424 ) 
Net increase (decrease) in cash and cash equivalents   457,685     348,593     (265,459 )    (12,716 ) 
Cash and cash equivalents at beginning of period   386,745     38,152     303,611     316,327  
Cash and cash equivalents at end of period $ 844,430   $ 386,745   $ 38,152   $ 303,611  
Supplemental Disclosure:
Interest paid, net of interest capitalized $ 588,972   $ 389,953   $ 351,532   $ 35,057  
Income taxes paid $ 101,225   $ 133,139   $ 94,405   $ —  

The accompanying notes are an integral part of these financial statements.

F-20

MIDAMERICAN ENERGY HOLDINGS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    Organization and Operations

MidAmerican Energy Holdings Company and its subsidiaries (the "Company" or "MEHC") is a United States-based privately owned global energy company. The Company's subsidiaries' principal businesses are regulated electric and natural gas utilities, regulated interstate natural gas transmission and electric power generation. Its operations are organized and managed on seven distinct platforms: MidAmerican Energy Company ("MidAmerican Energy"), Kern River Gas Transmission Company ("Kern River"), Northern Natural Gas Company ("Northern Natural Gas"), CE Electric UK Funding ("CE Electric UK") (which includes Northern Electric plc ("Northern Electric") and Yorkshire Power Group Ltd. ("Yorkshire")), CalEnergy Generation – Domestic, CalEnergy Generation-Foreign (the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively the "Leyte Projects") and the Casecnan Project) and HomeServices of America, Inc. ("HomeServices"). Through six of these platforms, the Company owns and operates a combined electric and natural gas utility company in the United States, two natural gas pipeline companies in the United States, two electricity distribution companies in the United Kingdom, and a diversified portfolio of domestic and international independent power projects. The Company also owns the second largest residential real estate brokerage firm in the United States.

On March 14, 2000, the Company and an investor group comprised of Berkshire Hathaway Inc., Walter Scott, Jr., a director of the Company, David L. Sokol, Chairman and Chief Executive Officer of the Company, and Gregory E. Abel, President and Chief Operating Officer of the Company, closed on a definitive agreement and plan of merger whereby the investor group acquired all of the outstanding common stock of the Company (the "Teton Transaction"). As a result of the Teton Transaction, Berkshire Hathaway, Mr. Scott, Mr. Sokol and Mr. Abel own approximately 9.7%, 86%, 3% and 1% of the voting stock respectively.

The Company initially incorporated in 1971 under the laws of the State of Delaware and was reincorporated in 1999 in Iowa, at which time it changed its name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.

In these notes to consolidated financial statements, references to "U.S. dollars," "dollars," "US $," "$" or "cents" are to the currency of the United States and references to "pounds sterling," "pounds," "sterling," "pence" or "p" are to the currency of the United Kingdom. References to MW means megawatts, MWh means megawatt hours, Bcf means billion cubic feet, mmcf means million cubic feet, GWh means gigawatts per hour, kV means 1000 volts, Tcf means trillion cubic feet, kWh means kilowatt hours and MMBtus means million British thermal units.

2.    Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Subsidiaries which are less than 100% owned but greater than 50% owned are consolidated with a minority interest. Subsidiaries that are 50% owned or less, but where the Company has the ability to exercise significant influence, are accounted for under the equity method of accounting. Investments where the Company's ability to influence is limited are accounted for under the cost method of accounting. All significant inter-enterprise transactions and accounts have been eliminated. The results of operations of the Company include the Company's proportionate share of results of operations of entities acquired from the date of each acquisition for purchase business combinations.

For the Company's foreign operations whose functional currency is not the U.S. dollar, the assets and liabilities are translated into U.S. dollars at current exchange rates. Resulting translation adjustments are reflected as accumulated other comprehensive income (loss) in stockholders' equity. Revenue and expenses are translated at average exchange rates for the period. Transaction gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency, except those transactions which operate as a hedge of an identifiable foreign currency commitment or as a hedge of a foreign currency investment position, are included in the results of operations as incurred.

F-21

Reclassifications

Certain amounts in the fiscal 2001 and 2000 consolidated financial statements and supporting note disclosures have been reclassified to conform to the fiscal 2002 presentation. Such reclassification did not impact previously reported net income or retained earnings.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Accounting for the Effects of Certain Types of Regulation

MidAmerican Energy, Kern River and Northern Natural Gas prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71 ("SFAS 71"), which differs in certain respects from the application of generally accepted accounting principles by non-regulated businesses. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, MidAmerican Energy, Kern River and Northern Natural Gas have deferred certain costs, which will be amortized over various future periods. To the extent that collection of such costs or payment of such obligations is no longer probable as a result of changes in regulation, the associated regulatory asset or liability is charged or credited to income.

A possible consequence of deregulation of the regulated energy industry is that SFAS 71 may no longer apply. If portions of the Company's subsidiaries' regulated energy operations no longer meet the criteria of SFAS 71, the Company could be required to write off the related regulatory assets and liabilities from its balance sheet, and thus a material adjustment to earnings in that period could result if regulatory assets or liabilities are not recovered in transition provisions of any deregulation legislation.

The Company continues to evaluate the applicability of SFAS 71 to its regulated energy operations and the recoverability of these assets and liabilities through rates as there are on-going changes in the regulatory and economic environment.

Cash and Cash Equivalents

The Company considers all investment instruments purchased with an original maturity of three months or less to be cash equivalents. Investments other than restricted cash are primarily commercial paper and money market securities. Restricted cash is not considered a cash equivalent.

Restricted Cash and Investments

The current restricted cash and short-term investments balance includes commercial paper and money market securities, and is mainly composed of amounts deposited in restricted accounts from which the Company will source its debt service reserve requirements relating to the projects. These funds are restricted by their respective project debt agreements to be used only for the related project.

The Company's nuclear decommissioning trust funds and other marketable securities are classified as available for sale and are accounted for at fair value.

Allowance for Doubtful Accounts

The allowance for doubtful accounts is based on the Company's assessment of the collectibility of payments from its customers. This assessment requires judgment regarding the outcome of pending disputes, arbitrations and the ability of customers to pay the amounts owed to the Company. Any change in the Company's assessment of the collectibility of accounts receivable that was not previously provided is recorded in the current period.

F-22

Fair Value of Financial Instruments

The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Although management uses its best judgment in estimating the fair value of these financial instruments, there are inherent limitations in any estimation technique. Therefore, the fair value estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a current transaction.

The methods and assumptions used to estimate fair value are as follows:

Short-term debt – Due to the short-term nature of the short-term debt, the fair value approximates the carrying value.

Debt instruments – The fair value of all debt issues listed on exchanges has been estimated based on the quoted market prices. The Company is unable to estimate a fair value for the Philippine term loans as there are no quoted market prices available.

Other financial instruments – All other financial instruments of a material nature are short-term and the fair value approximates the carrying amount.

Properties, Plants and Equipment, Net

Properties, plants and equipment are recorded at historical cost. The cost of major additions and betterments are capitalized, while replacements, maintenance, and repairs that do not improve or extend the lives of the respective assets are expensed.

Capitalized costs for gas reserves, other than costs of unevaluated exploration projects and projects awaiting development consent, are depleted using the units of production method. Depletion is calculated based on hydrocarbon reserves of properties in the evaluated pool estimated to be commercially recoverable and include anticipated future development costs in respect of those reserves.

Impairment of Long-Lived Assets

The Company's long-lived assets consist primarily of properties, plants and equipment. Depreciation is computed using the straight-line method based on economic lives or regulatory mandated recovery periods. The Company believes the useful lives assigned to the depreciable assets, which generally range from 3 to 87 years, are reasonable.

The Company periodically evaluates long-lived assets, including properties, plants and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Upon the occurrence of a triggering event, the carrying amount of a long-lived asset is reviewed to assess whether the recoverable amount has declined below its carrying amount. The recoverable amount is the estimated net future cash flows that the Company expects to recover from the future use of the asset, undiscounted and without interest, plus the asset's residual value on disposal. Where the recoverable amount of the long-lived asset is less than the carrying value, an impairment loss would be recognized to write down the asset to its fair value that is based on discounted estimated cash flows from the future use of the asset.

The estimate of cash flows arising from future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from future use of the asset. Any changes in the estimates of cash flows arising from future use of the asset or the residual value of the asset on disposal based on changes in the market conditions, changes in the use of the asset, management's plans, the determination of the useful life of the asset and technology changes in the industry could significantly change the calculation of the fair value or recoverable amount of the asset and the resulting impairment loss, which could significantly affect the results of operations. The determination of whether impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. An impairment analysis of generating facilities requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the facilities. A resulting impairment loss is highly dependent on these underlying assumptions.

F-23

Excess of Cost over Fair Value of Net Assets Acquired

On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142"), which establishes the accounting for acquired goodwill and other intangible assets, and provides that goodwill and indefinite-lived intangible assets will not be amortized, but will be tested for impairment on an annual basis. The Company's related amortization consisted primarily of goodwill amortization. Following is a reconciliation of net income available to common and preferred stockholders as originally reported for the years ended December 31, 2002 and 2001 and for the periods from March 14, 2000 through December 31, 2000 and January 1, 2000 through March 13, 2000, to adjusted net income available to common and preferred stockholders (in thousands):


  Year Ended December 31, March 14, 2000
through
December 31, 2000		 MEHC
(Predecessor)
January 1, 2000
through
March 13, 2000
  2002 2001
Reported net income available to common and preferred stockholders $ 380,043   $ 142,669   $ 81,257   $ 51,312  
Amortization of excess of cost over fair value of net assets acquired   —     96,418     79,997     14,181  
Tax effect of amortization   —     (2,018 )    (1,413 )    (372 ) 
Adjusted net income available to common and preferred stockholders $ 380,043   $ 237,069   $ 159,841   $ 65,121  

The Company completed its initial review pursuant to SFAS No. 142 for its reporting units during the second quarter of 2002 and its annual review during the fourth quarter of 2002. No impairment was indicated as a result of these assessments.

Capitalization of Interest and Allowance for Funds Used During Construction

Allowance for funds used during construction ("AFUDC") represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is realized in cash through depreciation provisions included in rates for subsidiaries that apply SFAS 71. Interest and AFUDC for subsidiaries that apply SFAS 71 are capitalized as a component of projects under construction and will be amortized over the assets' estimated useful lives.

Deferred Financing Costs

The Company capitalizes costs associated with financings, as deferred financing costs, and amortizes the amounts over the term of the related financing using the effective interest method.

Contingent Liabilities

The Company establishes reserves for estimated loss contingencies when it is management's assessment that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in operations in the period in which different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Reserves for contingent liabilities are based upon management's assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcomes of any matters. Should the outcomes differ from the assumptions and estimates, revisions to the estimated reserves for contingent liabilities would be required.

Deferred Income Taxes

The Company recognizes deferred tax assets and liabilities based on the difference between the financial statement and tax basis of assets and liabilities using estimated tax rates in effect for the year in which the differences are expected to reverse. The Company does not intend to repatriate earnings of foreign subsidiaries in the foreseeable future. As a result, deferred United States income taxes are not provided for retained earnings of international subsidiaries and corporate joint ventures unless the earnings are intended to be remitted.

F-24

Revenue Recognition

Revenue is recorded based upon services rendered and electricity, gas and steam delivered, distributed or supplied to the end of the period. The Company records unbilled revenue representing the estimated amounts customers will be billed for services rendered between the meter reading dates in a particular month and the end of that month. The unbilled revenue estimate is reversed in the following month. To the extent the estimated amount differs from the actual amount subsequently billed, revenue will be affected.

Where there is an over recovery of United Kingdom distribution business revenue against the maximum regulated amount, revenue is deferred in an amount equivalent to the over recovered amount. The deferred amount is deducted from revenue and included in other liabilities. Where there is an under recovery, no anticipation of any potential future recovery is made.

Revenue from the transportation and storage of gas are recognized based on contractual terms and the related volumes. Kern River and Northern Natural Gas are subject to the FERC's regulations and, accordingly, certain revenue collected may be subject to possible refunds upon final orders in pending rate cases. Kern River and Northern Natural Gas record rate refund liabilities considering their regulatory proceedings and other third party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks.

Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when title has transferred from seller to buyer. Title fee revenue from real estate transactions and related amounts due to the title insurer are recognized at the closing, which is when consideration is received. Fees related to loan originations are recognized at the closing, which is when services have been provided and consideration is received.

Financial Instruments

The Company currently utilizes swap agreements and forward purchase agreements to manage market risks and reduce its exposure resulting from fluctuation in interest rates, foreign currency exchange rates and electric and gas prices. For interest rate swap agreements, the net cash amounts paid or received on the agreements are accrued and recognized as an adjustment to interest expense. Gains and losses related to gas forward contracts are deferred and included in the measurement of the related gas purchases. These instruments are either exchange traded or with counterparties of high credit quality; therefore, the risk of nonperformance by the counterparties is considered to be negligible.

Accounting Principle Change

Effective January 1, 2001, the Company has changed its accounting policy regarding major maintenance and repairs for non-regulated gas projects, non-regulated plant overhaul costs and geothermal well rework costs to the direct expense method from the former policy of monthly accruals based on long-term scheduled maintenance plans for the gas projects and deferral and amortization of plant overhaul costs and geothermal well rework costs over the estimated useful lives. The cumulative effect of the change in accounting principle was $4.6 million, net of taxes of $0.7 million. If the Company had adopted the policy as of January 1, 2000, income before extraordinary item and cumulative effect of change in accounting principle would have been $6.3 million lower in 2000 on a pro forma basis.

New Accounting Pronouncements

In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and is effective January 1, 2003. This statement requires that the present value of retirement costs for which the Company has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The liability is then accreted over time by applying an interest method of allocation to the liability. Cumulative accretion and accumulated depreciation will be recognized for the time period from the date the liability would have been recognized had the provisions of this statement been in effect, to the date of adoption of this statement. The cumulative effect of initially applying this statement is recognized as a change in

F-25

accounting principle. The Company and its unconsolidated subsidiary used an expected cash flow approach to measure the obligations and adopted the statement as of January 1, 2003.

The Company's initial review of its regulated entities identified legal retirement obligations for nuclear decommissioning, wet and dry ash landfills and offshore and minor lateral pipeline facilities. The Company expects to record approximately $290.0 million of asset retirement obligation liabilities, approximately $265.0 million of which pertains to obligations associated with the decommissioning of the Quad Cities nuclear station. The adoption of this statement is not expected to have a material impact on the operations of the regulated entities, as the effects are expected to be offset by the establishment of regulatory assets, totaling approximately $115.0 million, pursuant to SFAS 71.

In addition, one of the Company's unconsolidated subsidiaries has identified legal retirement obligations for landfill and plant abandonment costs. The Company's share of this adoption is expected to total $1.1 million, net of tax.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 provides new guidance on the recognition of impairment losses on long-lived assets to be held and used or to be disposed of and also broadens the definition of what constitutes a discontinued operation and how the results of a discontinued operation are to be measured and presented. SFAS 144 supercedes SFAS No. 121 and APB Opinion No. 30, while retaining many of the requirements of these two statements. Under SFAS 144, assets held for sale that are a component of an entity will be included in discontinued operations if the operations and cash flows will be or have been eliminated from the ongoing operations of the entity and the entity will not have any significant continuing involvement in the operations prospectively. SFAS 144 did not materially change the methods used by the Company to measure impairment losses on long-lived assets but may result in more future dispositions being reported as discontinued operations than would previously have been permitted. The Company adopted SFAS 144 on January 1, 2002.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" ("SFAS 145"). SFAS 145 eliminates extraordinary accounting treatment for reporting gains or losses on debt extinguishment, and amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The provisions of SFAS 145 related to the rescission of FASB Statement No. 4 are applicable in fiscal years beginning after May 15, 2002, the provisions related to FASB Statement No. 13 are effective for transactions occurring after May 15, 2002, and all other provisions are effective for financial statements issued on or after May 15, 2002; however, early application is encouraged. Debt extinguishments reported as extraordinary items prior to scheduled or early adoption of SFAS 145 would be reclassified in most cases following adoption. The Company does not expect the adoption of SFAS 145 to have a material effect on its financial position, results of operations, or cash flows.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS 146"). SFAS 146 nullifies EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)" ("EITF 94-3"). The principal difference between SFAS 146 and EITF 94-3 relates to the requirements for recognition of a liability for costs associated with an exit or disposal activity. SFAS 146 requires that a liability be recognized for a cost associated with an exit or disposal activity when it is incurred. A liability is incurred when a transaction or event occurs that leaves an entity little or no discretion to avoid the future transfer or use of assets to settle the liability. Under EITF 94-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. In addition, SFAS 146 also requires that a liability for a cost associated with an exit or disposal activity be recognized at its fair value when it is incurred. SFAS 146 is effective for exit or disposal activities that are initiated after December 31, 2002 with early application encouraged. The Company will apply the provisions of SFAS 146 to all exit or disposal activities initiated after December 31, 2002.

In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 requires that a liability be recorded in the guarantor's balance sheet upon issuance of

F-26

certain guarantees. In addition, FIN 45 requires disclosures about the guarantees that an entity has issued. The provision for initial recognition and measurement of the liability will be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure provisions of FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002. The Company does not expect the adoption of FIN 45 to have a material effect on its financial position, results of operations, or cash flows.

3.    Acquisitions

Kern River

On March 27, 2002, the Company acquired Kern River, a 926-mile interstate pipeline transporting Rocky Mountain and Canadian natural gas to markets in California, Nevada and Utah.

The Company paid $419.7 million, net of cash acquired of $7.7 million and a working capital adjustment, for Kern River's gas pipeline business. The acquisition has been accounted for as a purchase business combination. The Company is in the process of completing the allocation of the purchase price to the assets and liabilities acquired. The results of operations for Kern River are included in the Company's results beginning March 27, 2002.

The recognition of excess of cost over fair value of net assets acquired resulted from various attributes of Kern River's operations and business in general. These attributes include, but are not limited to:

• Opportunities for expansion;
• High credit quality shippers contracting with Kern River;
• Kern River's strong competitive position;
• Exceptional operating track record and state-of-the-art technology;
• Strong demand for gas in the Western markets; and
• An ample supply of low-cost gas.

In connection with the acquisition of Kern River, the Company issued $323.0 million of 11% Company-obligated mandatorily redeemable preferred securities of subsidiary trust due March 12, 2012 with scheduled principal payments beginning in 2005 and $127.0 million of no par, zero coupon convertible preferred stock to Berkshire Hathaway. Each share of preferred stock is convertible at the option of the holder into one share of the Company's common stock subject to certain adjustments as described in the Company's Amended and Restated Articles of Incorporation.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):


Cash $ 7.7  
Properties, plants and equipment   797.2  
Excess of cost over fair value of net assets acquired   32.5  
Other assets   173.2  
Total assets acquired   1,010.6  
Current liabilities   (105.4 ) 
Long-term debt   (482.0 ) 
Other liabilities   (0.9 ) 
Total liabilities assumed   (588.3 ) 
Net assets acquired $ 422.3  

F-27

Northern Natural Gas Company

On August 16, 2002, the Company acquired Northern Natural Gas from Dynegy Inc. ("Dynegy"). Northern Natural Gas is a 16,600-mile interstate pipeline extending from southwest Texas to the upper Midwest region of the United States.

The Company paid $882.7 million for Northern Natural Gas, net of cash acquired of $1.4 million and net of a working capital adjustment. The acquisition has been accounted for as a purchase business combination. The Company is in the process of completing the allocation of the purchase price to the assets and liabilities acquired. The results of operations for Northern Natural Gas are included in the Company's results beginning August 16, 2002.

The recognition of excess of cost over fair value of net assets acquired resulted from various attributes of Northern Natural Gas' operations and business in general. These attributes include, but are not limited to:

• High credit quality shippers contracting with Northern Natural Gas;
• Northern Natural Gas' strong competitive position;
• Strategic location in the high demand Upper Midwest markets;
• Flexible access to an ample supply of low-cost gas;
• Exceptional operating track record; and
• Opportunities for expansion.

In connection with the acquisition of Northern Natural Gas, the Company issued $950.0 million of 11% Company-obligated mandatorily redeemable preferred securities of subsidiary trust due August 31, 2011, with scheduled principal payments beginning in 2003, to Berkshire Hathaway.

The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):


Cash $ 1.4  
Properties, plants and equipment   1,346.7  
Excess of cost over fair value of net assets acquired   414.7  
Other assets   309.9  
Total assets acquired   2,072.7  
Current portion of long-term debt   (450.0 ) 
Other current liabilities   (216.1 ) 
Long-term debt   (499.8 ) 
Other liabilities   (27.7 ) 
Total liabilities assumed   (1,193.6 ) 
Net assets acquired $ 879.1  

The following pro forma financial information of the Company represents the unaudited pro forma results of operations as if the Kern River and Northern Natural Gas acquisitions, and the related financings, had occurred at the beginning of each period. These pro forma results have been prepared for comparative purposes only and do not profess to be indicative of the results of operations which would have been achieved had these transactions been completed at the beginning of each year, nor are the results indicative of the Company's future results of operations (in millions).

F-28


  Year Ended
December 31,
  2002 2001
Revenue $ 5,299.4   $ 5,688.5  
Income before cumulative effect of change in accounting principle   285.5     36.9  
Net income available to common and preferred shareholders   285.5     32.3  

HomeServices' 2002 Acquisitions

In 2002, HomeServices separately acquired three real estate companies for an aggregate purchase price of approximately $106.1 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2001, these real estate companies had combined revenue of approximately $356.0 million on 42,000 closed sides representing $13.7 billion of sales volume. Additionally, HomeServices is obligated to pay a maximum earnout of $18.5 million based on 2002 financial performance measures. These purchases were financed using HomeServices' internally generated cash flows, revolving credit facility and $40.0 million from the Company, which was contributed to HomeServices as equity.

The acquisitions have been accounted for as a purchase business combination. The purchase price has been allocated to assets acquired and liabilities assumed. The Company recorded goodwill of approximately $108.9 million.

Yorkshire Swap

On September 21, 2001, CE Electric UK Ltd, an indirect wholly owned subsidiary of the Company, and Innogy Holdings, plc ("Innogy") executed an agreement to exchange Northern' Electrics electricity and gas supply and metering assets for Innogy's 94.75% interest in Yorkshire's electricity distribution business. Northern Electric's supply business was valued at approximately $391.0 million (£268.0 million), including working capital of approximately $14.0 million (£10.0 million). 94.75% of Yorkshire's distribution business was valued at approximately $405.0 million (£278.0 million), including working capital of approximately $58.0 million (£40.0 million). The net cash paid by Northern Electric for the exchange was approximately $14.0 million (£10.0 million).

The disposition of Northern Electric's supply business created a pre-tax non-recurring gain of $196.7 million and an after-tax gain of $10.8 million. Included in the carrying value of the Northern Electric supply business was $504.4 million of goodwill allocated based on the relative fair values of the Northern Electric supply business.

The Company paid $57.4 million, net of cash acquired of $353.8 million and transaction costs, for 94.75% of the Yorkshire electricity distribution business and related indebtedness. The acquisition has been accounted for as a purchase business combination. The results of operations for Yorkshire are included in the Company's results beginning September 21, 2001.

Teton Transaction

On October 24, 1999, the Company and an investor group comprised of Berkshire Hathaway, Walter Scott, Jr., and David L. Sokol, executed a definitive agreement and plan of merger whereby the investor group would acquire all of the outstanding common stock of the Company for $35.05 per share in cash, representing a total purchase price of approximately $2.2 billion, including transaction costs. The Teton Transaction closed on March 14, 2000 and Berkshire Hathaway invested approximately $1.24 billion in common stock and convertible preferred stock and approximately $455 million in 11% nontransferable trust preferred securities due March 14, 2010. Mr. Scott, Mr. Sokol and Gregory E. Abel contributed cash and current securities of the Company having a value of approximately $310 million. The remaining purchase price was funded with the Company's cash. Berkshire Hathaway owns approximately 9.7% of the voting stock, Mr. Scott owns approximately 86% of the voting stock, Mr. Sokol owns approximately 3% of the voting stock and Mr. Abel owns approximately 1% of the voting stock.

F-29

The merger has been accounted for as a purchase business combination. The purchase price has been allocated to assets acquired and liabilities assumed. The Company recorded goodwill of approximately $1.2 billion.

4.    Dispositions and Other Non-recurring Items

CE Gas Asset Sale

In May 2002, CE Gas, an indirect wholly owned subsidiary of the Company, executed the sale of several of its U.K. natural gas assets to Gaz de France for £137.0 million (approximately $200.0 million). CE Gas sold four natural gas-producing fields located in the southern basin of the U.K. North Sea, including Anglia, Johnston, Schooner and Windermere. The transaction also included the sale of rights in four gas fields (in development/construction) and three exploration blocks owned by CE Gas. The Company recorded pre-tax and after-tax income of $54.3 million and $41.3 million, respectively, which includes a write off of non-deductible goodwill of $49.6 million.

Telephone Flat Sale

On October 16, 2001, the Company closed on a transaction that transferred all properties and rights of the Telephone Flat Project, a geothermal development project in northern California to Calpine Corp. The Company recorded a pre-tax gain of $20.7 million and an after-tax gain of $12.2 million on the sale of the Telephone Flat Project.

Western States Sale

On June 30, 2001, the Company closed on a transaction in which the Company sold Western States Geothermal, an indirect wholly owned subsidiary of the Company, to Ormat. The Company recorded a pre-tax gain of $9.8 million and an after-tax gain of $6.4 million on the sale of Western States Geothermal.

Tesside Power Limited ("TPL")

In December 2001, the Company recorded a non-recurring charge of $20.7 million, net of tax, representing an asset valuation impairment charge under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets" ("SFAS 121") relating to the Company's 15.4% interest in TPL. TPL owns and operates a 1,875 MW combined cycle gas-fired power plant. Enron Corp. ("Enron"), through its subsidiaries, owned a 42.5% interest, operated the plant, and purchased 668 MW of capacity. Enron's subsidiary, which owns and operates TPL, is now in administration and administrators have been appointed to run its business and are attempting to find a buyer.

Shareholders in TPL had previously utilized TPL's taxable losses with an obligation to reimburse TPL later in the project's life. In May 2002, TPL executed a restructuring and stabilization agreement with its lenders. The contract included an agreement between TPL and its shareholders with respect to the waiver of these repayment obligations. In May 2002, TPL released $35.7 million due to the repayment obligation being waived which is reflected as a tax benefit in the provision for income taxes.

F-30

5.    Properties, Plants and Equipment, Net

Properties, plants and equipment, net comprise the following at December 31 (in thousands):


  Estimated
Useful Lives
(Years)		 December 31,
  2002 2001
Properties, plants and equipment, net:
Utility generation and distribution system   10-50   $ 8,165,140   $ 7,574,339  
Interstate pipelines' assets   3-87     2,171,436     —  
Independent power plants   10-30     1,410,170     1,402,102  
Mineral and gas reserves and exploration assets   5-30     495,423     387,697  
Utility non-operational assets   3-30     370,811     354,366  
Other assets   3-10     130,755     153,211  
Total operating assets         12,743,735     9,871,715  
Accumulated depreciation and amortization         (4,104,133 )    (3,650,875 ) 
Net operating assets         8,639,602     6,220,840  
Construction in progress         1,170,485     316,531  
Properties, plants and equipment, net       $ 9,810,087   $ 6,537,371  

Construction in Progress

MidAmerican Energy is constructing a 500-MW (based on expected accreditation) natural gas-fired, combined cycle plant with an estimated cost of $415 million. MidAmerican Energy will own 100% of the plant and operate it. The plant will be operated in simple cycle mode during 2003 and 2004, resulting in 310 MW of accredited capacity. The combined cycle operation will commence in 2005. MidAmerican Energy has received a certificate from the Iowa Utilities Board, "(IUB"), allowing it to construct the plant. In May 2002, the IUB issued an order that specified the Iowa ratemaking principles that will apply to the plant over its life. As a result of that order, MidAmerican Energy is proceeding with the construction of the plant.

The 2003 Expansion Project is a new parallel 717-mile loop pipeline that will begin in Lincoln County, Wyoming and terminate in Kern County, California. The 2003 Expansion Project began construction on August 6, 2002 and is expected to be completed and operational by May 1, 2003 at a total cost of approximately $1.2 billion. The pipeline will include 36- and 42-inch diameter pipe, most of which will be laid in the existing Kern River rights-of-way at a 25-foot offset from the existing pipeline, and new above ground facilities. Three segments along the rights-of-way, approximately 205 miles in Utah, Nevada and California, will not require additional pipeline but will instead be areas where the gas will be compressed and transported through the existing pipeline. The existing pipeline rights-of-way, compressor facilities and receipt/delivery facilities will all be utilized by the 2003 Expansion Project, streamlining the permitting, acquisition of rights-of-way and ultimately the construction and operations of the 2003 Expansion Project.

The 2003 Expansion Project includes the construction of three new compressor stations and the installation of additional compression and other modifications at six existing facilities. When completed, the Kern River system will have a summer day design capacity of approximately 1.73 Bcf per day, an increase of approximately 886 mmcf per day.

6.    Investment in CE Generation

Since the sale of 50% of its interests in CE Generation on March 3, 1999, the Company has accounted for CE Generation as an equity investment. The equity investment in CE Generation at December 31, 2002 and 2001 was approximately $244.9 million and $233.6 million, respectively. The following is summarized financial information for CE Generation as of and for the years ended December 31 (in thousands):

F-31


  2002 2001 2000
Revenue $ 510,082   $ 565,838   $ 510,796  
Income before cumulative effect of change in accounting principle   58,314     74,194     73,535  
Net income   58,314     58,808     73,535  
Current assets   202,490     211,635        
Total assets   1,865,036     1,932,119        
Current liabilities   150,165     155,808        
Long-term debt, including current portion   1,011,220     1,096,256        

7.    Other Investments

Williams' Company Preferred Stock

On March 27, 2002, a newly formed subsidiary of the Company, MEHC Investments Inc., invested $275.0 million in Williams in exchange for shares of 9 7/8% cumulative convertible preferred stock of Williams. Dividends on the Williams' preferred stock are scheduled to be received quarterly, which commenced July 1, 2002. This investment is accounted for under the cost method. Since the date of this investment, there have been public announcements that Williams' financial condition has deteriorated as a result of, among other factors, reduced liquidity. The Company has not recorded an impairment on this investment as of December 31, 2002, and is monitoring the situation.

Investments in Debt and Equity Securities

Substantially all of the Company's investments in debt and equity securities relate to its Quad Cities Station decommissioning trust. The amortized cost, gross unrealized gain and losses and estimated fair value of investments in debt and equity securities comprise the following at December 31 (in thousands):


  2002
  Amortized
Cost		 Unrealized
Gains		 Unrealized
Losses		 Fair
Value
Available-for-sale:
Equity securities $ 56,265   $ 16,373   $ (1,313 )  $ 71,325  
Municipal bonds   30,915     918     (263 )    31,570  
U. S. Government securities   18,511     183     (119 )    18,575  
Corporate securities   25,258     1,152     (80 )    26,330  
Cash equivalents   12,718     —     —     12,718  
Total available-for-sale $ 143,667   $ 18,626   $ (1,775 )  $ 160,518  
Held-to-Maturity:
Debt securities $ 2,070   $ —   $ —   $ 2,070  
U.S. Treasury Strips   1,485     208     —     1,693  
Agency obligations   216     111     —     327  
Total held-to-maturity $ 3,771   $ 319   $ —   $ 4,090  

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  2001
  Amortized
Cost		 Unrealized
Gains		 Unrealized
Losses		 Fair
Value
Available-for-sale:
Equity securities $ 53,663   $ 24,444   $ (3,144 )  $ 74,963  
Municipal bonds   27,842     1,315     (92 )    29,065  
U. S. Government securities   26,725     1,910     (19 )    28,616  
Corporate securities   18,682     812     (23 )    19,471  
Cash equivalents   7,120     —     —     7,120  
Total available-for-sale $ 134,032   $ 28,481   $ (3,278 )  $ 159,235  
Held-to-Maturity:
Debt securities $ 2,074   $ —   $ —   $ 2,074  
U.S. Treasury Strips   1,090     85     —     1,175  
Agency obligations   611     —     (22 )    589  
Total held-to-maturity $ 3,775   $ 85   $ (22 )  $ 3,838  

At December 31, 2002, the debt securities held by the Company had the following maturities (in thousands):


  Available For Sale Held To Maturity
  Amortized
Cost		 Fair
Value		 Amortized
Cost		 Fair
Value
Within 1 year $ 7,224   $ 7,384   $ 2,070   $ 2,070  
1 through 5 years   25,143     25,994     479     664  
5 through 10 years   14,190     14,574     1,222     1,356  
Over 10 years   27,621     28,020     —     —  

The proceeds and gross realized gains and losses on the disposition of available-for-sale and held-to-maturity investments are shown in the following table (in thousands). Realized gains and losses are determined by specific identification.


  Year Ended
December 31,		 March 14, 2000
through
December 31, 2000		 MEHC (Predecessor)
January 1, 2000
through
March 13, 2000
  2002 2001
Proceeds from sales $ 151,394   $ 68,333   $ 93,531   $ 22,588  
Gross realized gains   7,099     2,676     6,464     1,560  
Gross realized losses   (7,792 )    (7,314 )    (10,585 )    (2,556 ) 

8.    Short-Term Debt

Short-term debt comprises the following at December 31 (in thousands):


  2002 2001
Short-term debt:
Corporate revolving credit facility $ —   $ 153,500  
MidAmerican Energy short-term debt   55,000     91,780  
HomeServices revolving credit facilities   24,750     9,000  
Other   32     1,732  
Total short-term debt $ 79,782   $ 256,012  

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Corporate Revolving Credit Facilities

The Company has a $400.0 million revolving credit facility which expires in June 2003. The facility is unsecured and available to fund working capital requirements and other corporate requirements. The facility carries a variable interest rate based on LIBOR and ranged from 2.625% to 2.8625% in 2002. No borrowings were outstanding at December 31, 2002. The Company plans to renew the facility in June 2003.

MidAmerican Energy Short-Term Debt

As of December 31, 2002, MidAmerican Energy had in place a $370.4 million revolving credit facility that supports its $250.0 million commercial paper program and its variable rate pollution control revenue obligations. In addition, MidAmerican Energy has a $5.0 million line of credit. As of December 31, 2002, commercial paper and bank notes totaled $55.0 million for MidAmerican Energy. MHC Inc., an indirect wholly owned subsidiary of the Company, has a $4.0 million line of credit under which no borrowings were outstanding at December 31, 2002. The commercial paper, bank notes and outstanding line of credit have a weighted average interest rate of 1.29% at December 31, 2002.

HomeServices Revolving Credit Facilities

Upon the expiration of its $65.0 million senior secured revolving credit facility in November 2002, HomeServices entered into a new $125.0 million senior secured revolving credit agreement. The new revolving credit agreement has a term of three years and is secured by a pledge of the capital stock of all of the existing and future subsidiaries of HomeServices. Amounts outstanding under this revolving credit facility bear interest, at HomeServices' option, at either the prime lending rate or LIBOR plus a fixed spread of 1.25% to 2.25%, which varies based on HomeServices' cash flow leverage ratio (1.25% at December 31, 2002). As of December 31, 2002, the outstanding balance of $24.8 million had a weighted average interest rate of 2.6661%.

9.    Parent Company Debt

Parent company debt is unsecured senior obligations of the Company and comprises the following at December 31 (in thousands):


  2002 2001
Parent company debt:
6.96% Senior Notes, due 2003 $ 215,000   $ 215,000  
7.23% Senior Notes, due 2005   260,000     260,000  
4.625% Senior Notes, due 2007   200,000     —  
7.63% Senior Notes, due 2007   350,000     350,000  
7.52% Senior Notes, due 2008   450,000     450,000  
7.52% Senior Notes, due 2008 (Series B)   101,481     101,680  
5.875% Senior Notes, due 2012   500,000     —  
8.48% Senior Notes, due 2028   475,000     475,000  
Fair value adjustments and other   (12,025 )    (17,182 ) 
Total parent company debt   2,539,456     1,834,498  
Less current portion   (215,000 )    —  
Total long-term parent company debt $ 2,324,456   $ 1,834,498  

Interest on the 7.63% Senior Notes is payable semiannually on April 15 and October 15 of each year. Interest on the 3.5% Senior Notes and the 5.875% Senior Notes is payable semiannually on January 31 and July 31 of each year. Interest on the remaining parent company debt is payable semiannually on March 15 and September 15 of each year.

10.    Subsidiary and Project Loans

Each of the Company's direct and indirect subsidiaries is organized as a legal entity separate and apart from the Company and its other subsidiaries. Pursuant to separate project financing agreements, the

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assets of each subsidiary are pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should not be assumed that any asset of any such subsidiary will be available to satisfy the obligations of the Company or any of its other such subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to the Company or affiliates thereof.

Project loans held by subsidiaries and projects comprise the following at December 31 (in thousands):


  2002 2001
Subsidiary and project loans:
MidAmerican Funding Senior Notes and Bonds $ 700,000   $ 700,000  
MidAmerican Energy Mortgage Bonds   340,570     340,570  
MidAmerican Energy Pollution Control Bonds   155,745     157,185  
MidAmerican Energy Notes   560,000     322,240  
MidAmerican Capital Notes   —     23,333  
Northern Electric Eurobonds   322,811     291,643  
CE Electric UK Senior Notes and Sterling Bonds   677,642     646,500  
Yorkshire   1,573,136     1,491,597  
CE Gas Loan   —     70,180  
Kern River Senior Notes   488,000     —  
Kern River Construction Financing Facility   789,916     —  
Northern Natural Gas Senior Notes   799,406     —  
Cordova Funding Senior Secured Bonds   223,763     225,000  
Salton Sea Funding Corporation Series F Bonds   137,789     139,896  
Casecnan Notes and Bonds   287,925     320,138  
Philippine Term Loans   244,961     313,221  
HomeServices Senior Notes and Other   39,031     36,780  
Other, including fair value adjustments   (8,395 )    (6,292 ) 
Total subsidiary and project loans .   7,332,300     5,071,991  
Less current portion   (255,213 )    (317,180 ) 
Total long-term subsidiary and project loans. $ 7,077,087   $ 4,754,811  

MidAmerican Funding Senior Notes and Bonds

On March 11, 1999, MidAmerican Funding, a wholly owned subsidiary of the Company, issued $200.0 million of 5.85% Senior Secured Notes due in 2001, $175.0 million of 6.339% Senior Secured Notes due in 2009, and $325.0 million of 6.927% Senior Secured Bonds due in 2029. The proceeds from the offering were used to complete the MidAmerican acquisition in 1999.

On March 1, 2001 MidAmerican Funding retired $200.0 million of 5.85% Senior Secured Notes due 2001. On March 19, 2001 MidAmerican Funding issued $200 million of 6.75% Senior Secured Notes due March 1, 2011.

MidAmerican Funding uses distributions that it receives from its subsidiaries to make payments on the Senior Notes and Bonds. These subsidiaries must make payments on their own indebtedness before making distributions to MidAmerican Funding. The distributions are also subject to utility regulatory restrictions agreed to by MidAmerican Energy in March 1999 whereby it committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain its common equity level above 42% of total capitalization unless circumstances beyond its control result in the common equity level decreasing to below 39% of total capitalization. MidAmerican Funding must seek the approval of the IUB of a reasonable utility capital structure if MidAmerican Energy's common equity level decreases below 42% of total capitalization, unless the decrease is beyond the control of MidAmerican Funding. MidAmerican Funding is also required to seek the approval of the

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IUB if MidAmerican Energy's equity level decreases to below 39%, even if the decrease is due to circumstances beyond the control of MidAmerican Funding.

MidAmerican Energy Mortgage Bonds, Pollution Control Bonds and Notes

The components of MidAmerican Energy's Mortgage Bonds, Pollution Control Bonds and Notes comprise the following at December 31 (in thousands):


  2002 2001
Mortgage bonds:
7.125% Series, due 2003 $ 100,000   $ 100,000  
7.70% Series, due 2004   55,630     55,630  
7% Series, due 2005   90,500     90,500  
7.375% Series, due 2008   75,000     75,000  
7.45% Series, due 2023   6,940     6,940  
6.95% Series, due 2025   12,500     12,500  
Total mortgage bonds $ 340,570   $ 340,570  
Pollution control revenue obligations:
5.75% Series, due periodically through 2003 $ 4,320   $ 5,760  
5.95% Series, due 2023   29,030     29,030  
6.7% Series, due 2003   1,000     1,000  
6.1% Series, due 2007   1,000     1,000  
Variable rate series:
Due 2016 and 2017, 1.64% and 1.77% respectively   37,600     37,600  
Due 2023 (secured by general mortgage bond, 1.64% and 1.77%, respectively   28,295     28,295  
Due 2023, 1.64% and 1.77%, respectively   6,850     6,850  
Due 2024, 1.64% and 1.77%, respectively   34,900     34,900  
Due 2025, 1.64% and 1.77%, respectively   12,750     12,750  
Total pollution control revenue obligations $ 155,745   $ 157,185  
Notes:
8.75% Series, due 2002 $ —   $ 240  
7.375% Series, due 2002   —     162,000  
6.75% Series, due 2031   400,000     —  
6.375% Series, due 2006   160,000     160,000  
Total notes $ 560,000   $ 322,240  

On February 8, 2002, MidAmerican Energy issued $400 million of 6.75% notes due in 2031. The proceeds were used to refinance existing debt and preferred securities and for other corporate purposes. On March 11, 2002, MidAmerican Energy redeemed its MidAmerican Energy-obligated mandatorily redeemable preferred securities of subsidiary trust at 100% of the principal amount plus accrued interest.

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CE Electric UK, Northern Electric and Yorkshire Electric Eurobonds, Senior Notes and Sterling Bonds


  2002 2001
Eurobonds:
8.625% Bearer bonds, due 2005 $ 161,469   $ 145,879  
8.875% Bearer bonds, due 2020   161,342     145,764  
Total eurobonds $ 322,811   $ 291,643  
Senior Notes and Sterling Bonds:
6.853% Senior Notes, due 2004 $ 124,590   $ 124,613  
6.995% Senior Notes, due 2007   236,223     235,937  
7.25% Sterling Bonds, due 2022   316,829     285,950  
Total senior notes and sterling bonds $ 677,642   $ 646,500  
Yorkshire:
9.25% Eurobonds, due 2020 $ 421,896   $ 383,576  
7.25% Eurobonds, due 2028   342,539     311,427  
Variable Rate Reset Trust Securities, due 2020 (5.04% at December 31, 2002)   258,821     235,313  
8.08% Trust Securities, due 2038   249,695     261,082  
6.496% Yankee Bonds, due 2008   300,185     300,199  
Total Yorkshire Electric debt $ 1,573,136   $ 1,491,597  

The CE Electric UK Senior Notes and Sterling Bonds prohibit distributions to any of its stockholders unless certain financial ratios are met by CE Electric UK or the long-term debt rating is above a prescribed level.

The Yorkshire Electric Debt prohibits distributions to any of its stockholders unless certain financial ratios are met by Yorkshire or the long-term debt rating is above a prescribed level.

On February 15, 2005, the Yorkshire Variable Rate Reset Trust Securities may be remarketed by the underwriter at a fixed rate of interest through the maturity date or, at a floating rate of interest for up to one year and then at fixed rate of interest through 2020, or redeemed by Yorkshire.

Kern River Senior Notes and Construction Financing Facility

On August 13, 2001, Kern River issued $510.0 million in debt securities. The offering was in the form of $510.0 million of 15-year amortizing Senior Notes bearing a fixed rate of interest of 6.676%. For the Senior Notes, $405.0 million will be amortized through June 2016, with a final payment of $105.0 million to be made on July 31, 2016. As of December 31, 2002, the balance of the Kern River Senior Notes was $488.0 million.

On July 17, 2002, Kern River received approval from the FERC to construct, own and operate the 2003 Expansion Project. The estimated cost of the expansion is approximately $1.2 billion and is being be financed with approximately 70% debt and 30% equity, consistent with Kern River's original capital structure, the application for the FERC approval described above and the limitations contained in the indenture for Kern River's existing senior notes.

Construction is being initially funded with the proceeds of the $875.0 million credit facility entered into by Kern River on June 21, 2002, for approximately 70% of the projected capitalized costs of the 2003 Expansion Project. The remaining approximately 30% of the capitalized costs of the 2003 Expansion Project is being funded with equity from the Company. As of December 31, 2002, the balance of the Kern River construction financing facility was $789.9 million.

Northern Natural Gas Senior Notes

The components of Northern Natural Gas' Senior Notes comprise the following at December 31 (in thousands):

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  2002
6.875% Senior Notes, due 2005 $ 100,000  
6.75% Senior Notes, due 2008   150,000  
7.00% Senior Notes, due 2011   250,000  
5.375% Senior Notes, due 2012   300,000  
Unamortized debt discount   (594 ) 
Total Senior Notes $ 799,406  

Cordova Funding Senior Secured Bonds

On September 10, 1999, Cordova Funding Corporation ("Cordova Funding"), a wholly owned subsidiary of the Company, closed the $225.0 million aggregate principal amount financing for the construction of the Cordova Project. The proceeds were loaned to Cordova Energy and comprise the following at December 31 (in thousands):


  2002 2001
8.64% Senior Secured Bonds, due 2019 $ 93,001   $ 93,515  
8.79% Senior Secured Bonds, due 2019   31,137     31,309  
9.07% Senior Secured Bonds, due 2019   29,139     29,300  
8.48% Senior Secured Bonds, due 2019   12,685     12,755  
8.82% Senior Secured Bonds, due 2019   57,801     58,121  
Total Senior Secured Bonds $ 223,763   $ 225,000  

MEHC has guaranteed a specified portion of the final scheduled principal payment on December 15, 2019 on the Cordova Funding Senior Secured Bonds in an amount up to a maximum of $37.0 million. MEHC also provides a debt service reserve guarantee in an amount equal to the principal, premium, if any, and interest payment due on the bonds on the next scheduled payment date which was equal to $14.3 million at December 31, 2002.

Salton Sea Funding Corporation Series F Bonds

Salton Sea Funding Corporation, an indirect wholly owned subsidiary of CE Generation, had a debt balance of $491.7 million at December 31, 2002. Minerals is one of several guarantors of the Salton Sea Funding Corporation's debt. As a result of a note allocation agreement, Minerals is primarily responsible for $137.8 million of the 7.475% Senior Secured Series F Bonds due November 30, 2018. MEHC has guaranteed a specified portion of the scheduled debt service on the Series F Bonds equal to this current principal amount of $137.8 million and associated interest.

Casecnan Notes and Bonds

On November 27, 1995, CE Casecnan Ltd. ("CE Casecnan") issued $371.5 million of notes and bonds to finance the construction of the Casecnan Project. The Casecnan notes and bonds comprise the following at December 31 (in thousands):


  2002 2001
Casecnan notes and bonds:
Senior Secured Floating Rate Notes (FRNs), due in 2002 $ —   $ 23,638  
11.45% Senior Secured Series A Notes, due in 2005   125,000     125,000  
11.95% Senior Secured Series B Bonds, due in 2010   162,925     171,500  
Total Casecnan notes and bonds $ 287,925   $ 320,138  

The Casecnan Notes and Bonds are subject to redemption at the Company's option as provided in the Trust Indenture. The Casecnan Notes and Bonds are also subject to mandatory redemption based on certain conditions.

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Philippine Term Loans

The Export-Import Bank of the United States ("Ex-Im Bank") provided term loan financing for the Company's Mahanagdong geothermal power project of $92.8 million at a fixed rate of 6.92%. The Overseas Private Investment Corporation ("OPIC") is providing term loan financing of $20.6 million at a fixed interest rate of 7.6%. The loans have scheduled repayments through June 2007.

OPIC provided term loan financing for the Company's Malitbog geothermal power project of $22.7 million that was fixed at an interest rate of 9.176%. A syndicate of international commercial banks is providing term loan financing of $40.9 million at a variable interest rate based on LIBOR (3.84% at December 31, 2002). The loans have scheduled repayments through June 2005.

Ex-Im provided term loan financing for the Company's Upper Mahiao geothermal power project of $63.1 million at a fixed interest rate of 5.95%. United Coconut Planters Bank of the Philippines is providing term loan financing of $5.0 million at a variable interest rate based on LIBOR (4.42% at December 31, 2002). The loans have scheduled repayments through June 2006.

The Philippine term loans comprise the following at December 31 (in thousands):


  2002 2001
Philippine term loans:
Mahanagdong Project 7.60% Term Loan, due 2007 $ 20,571   $ 25,143  
Mahanagdong Project 6.92% Term Loan, due 2007   92,766     113,381  
Malitbog Project Variable Rate Term Loan, due 2005 3.84% and 4.295%, respectively   40,890     55,402  
Malitbog Project 9.176% Term Loan, due 2006   22,677     30,725  
Upper Mahiao Project Variable Rate Term Loan, due 2003 4.42% and 5.130%, respectively   5,000     6,111  
Upper Mahiao Project 5.95% Term Loan, due 2006   63,057     82,459  
Total Philippine term loans $ 244,961   $ 313,221  

HomeServices Senior Notes and Other

In November 1998, HomeServices issued $35.0 million of 7.12% fixed-rate private placement senior notes due in annual increments of $5.0 million beginning in 2004. As of December 31, 2002, the balance of the HomeServices Senior Notes was $35.0 million.

In addition to the senior notes, HomeServices' has outstanding notes, with varying interest rates, totaling $4.0 million at December 31, 2002.

Annual Repayments of Debt

The annual repayments of debt for the years beginning January 1, 2003 and thereafter are as follows (in thousands):

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  2003 2004 2005 2006 2007 Thereafter Total
Parent, Subsidiary and Project loans:
Parent Company Debt $ 215,000   $ —   $ 260,000   $ —   $ 550,000   $ 1,514,456   $ 2,539,456  
MidAmerican Funding Senior Notes and Bonds   —     —     —     —     —     700,000     700,000  
MidAmerican Energy Mortgage Bonds   100,000     55,630     90,500     —     —     94,440     340,570  
MidAmerican Energy Pollution Control Bonds   5,727     —     —     —     1,000     149,018     155,745  
MidAmerican Energy Notes   —     —     —     160,000     —     400,000     560,000  
Northern Electric Eurobonds   —     —     161,469     —     —     161,342     322,811  
CE Electric UK Senior Notes and Sterling Bonds   —     124,590     —     —     236,223     316,829     677,642  
Yorkshire   —     —     —     —     —     1,573,136     1,573,136  
Kern River Senior Notes   24,000     25,000     26,000     26,000     26,000     361,000     488,000  
Kern River Construction Financing Facility   —     —     —     —     —     789,916     789,916  
Northern Natural Gas Senior
Notes 		  —     —     100,000     —     —     699,406     799,406  
Cordova Funding Senior Secured Bonds   9,000     8,100     7,875     4,500     4,162     190,126     223,763  
Salton Sea Funding Corporation Series F Bonds   1,405     1,757     1,756     1,827     1,055     129,989     137,789  
Casecnan Notes and Bonds   41,468     49,360     54,752     36,015     37,730     68,600     287,925  
Philippine Term Loans   72,148     67,148     63,034     30,037     12,594     —     244,961  
HomeServices Senior Notes and Other   1,465     5,133     5,048     5,036     5,024     17,325     39,031  
Other, including fair value adjustments         —     —     —     —     (8,395 )    (8,395 ) 
Total parent, subsidiary and project loans $ 470,213   $ 336,718   $ 770,434   $ 263,415   $ 873,788   $ 7,157,188   $ 9,871,756  

Fair Value

At December 31, 2002, the Company had fixed-rate long-term debt, Company-obligated mandatorily redeemable preferred securities of subsidiary trusts, and subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts of $11,683.2 million in principal amount and having a fair value of $12,188.8 million. In addition, at December 31, 2002, the Company had floating-rate obligations of $425.1 million that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates.

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11.    Income Taxes

Provision for income taxes was comprised of the following (in thousands):


  Year Ended
December 31,		 March 14, 2000
through
December 31, 2000		 MEHC (Predecessor)
January 1, 2000
through
March 13, 2000
  2002 2001
Current:
Federal $ 46,714   $ 51,025   $ 17,387   $ 9,147  
State   14,516     2,669     10,527     (1,886 ) 
Foreign   54,586     43,450     40,823     16,012  
    115,816     97,144     68,737     23,273  
Deferred:
Federal $ (7,073 )  $ (14,004 )  $ (32,469 )  $ 1,854  
State   (9,675 )    (342 )    (1,933 )    834  
Foreign   520     167,266     18,942     5,047  
    (16,228 )    152,920     (15,460 )    7,735  
Total $ 99,588   $ 250,064   $ 53,277   $ 31,008  

A reconciliation of the federal statutory tax rate to the effective tax rate applicable to income before provision for income taxes follows:


      
Year Ended
December 31,		 March 14, 2000
through
December 31, 2000		 MEHC
(Predecessor)
January 1, 2000
through
March 31, 2000
  2002 2001
Federal statutory rate   35.0 %    35.0 %    35.0 %    35.0 % 
Investment and energy tax credits   (0.7 )    (1.0 )    (2.3 )    (0.7 ) 
State taxes, net of federal tax effect   1.2     3.2     2.6     (0.8 ) 
Goodwill amortization   —     5.9     12.1     5.9  
Dividends on preferred securities of subsidiary trusts   (8.1 )    (6.1 )    (11.1 )    (2.8 ) 
Tax effect of foreign income   (4.8 )    (2.5 )    (5.8 )    (5.0 ) 
Non-recurring items on CE Electric UK, net of tax effect of foreign income   (8.1 )    19.2     —     —  
Dividends received deduction   (1.8 )    (2.6 )    (6.8 )    (1.0 ) 
Other items, net   2.8     (1.5 )    0.6     3.4  
Effective tax rate   15.5 %    49.6 %    24.3 %    34.0 % 

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Deferred tax liabilities (assets) comprise the following at December 31 (in thousands):


  2002 2001
Properties, plants and equipment, net $ 1,325,228   $ 1,133,286  
Income taxes recoverable through future rates   159,411     185,222  
Employee benefits   65,537     68,514  
Reacquired debt   4,914     7,544  
Fuel cost recoveries   —     20,272  
Other   121     —  
    1,555,211     1,414,838  
Minimum pension liability adjustment   (140,854 )    (5,147 ) 
Revenue sharing accruals   (48,861 )    (24,769 ) 
Accruals not currently deductible for tax purposes   (59,083 )    (47,287 ) 
Nuclear reserve and decommissioning   (28,411 )    (17,898 ) 
Deferred income   (21,733 )    (24,732 ) 
Fuel cost recoveries   (9,558 )    —  
NOL and credit carryforwards   (8,290 )    (5,567 ) 
Other   —     (5,170 ) 
    (316,790 )    (130,570 ) 
Net deferred income taxes $ 1,238,421   $ 1,284,268  

12.    Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

The Company has organized special purpose Delaware business trusts (collectively, the "Trusts") pursuant to their respective amended and restated declarations of trusts (collectively, the "Declarations"). The Company, through these Trusts, issued Company-obligated mandatorily redeemable preferred securities (collectively, the "Trust Securities") as follows (in thousands):


  2002 2001
CalEnergy Capital Trust II – 6.25% preferred securities, due 2012 $ 155,538   $ 155,584  
CalEnergy Capital Trust III – 6.5% preferred securities, due 2027   269,980     269,984  
MidAmerican Capital Trust I – 11% preferred securities, due 2010   454,772     454,772  
MidAmerican Capital Trust II – 11% preferred securities, due 2012   323,000     —  
MidAmerican Capital Trust III – 11% preferred securities, due 2012   950,000     —  
Fair value adjustment   (89,878 )    (92,189 ) 
Total Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts $ 2,063,412   $ 788,151  

The Company owns all of the common securities of the Trusts. The Trust Securities have a liquidation preference of $50 each and represent undivided beneficial ownership interests in each of the Trusts. The assets of the Trusts consist solely of the Company's Subordinated Debentures (collectively, the "Junior Debentures") issued pursuant to their respective indentures. The indentures include agreements by the Company to pay expenses and obligations incurred by the Trusts.

Prior to the Teton Transaction, each Trust Security issued by CalEnergy Capital Trust II and III with a par value of $50 was convertible at the option of the holder at any time into shares of the Company's common stock based on the conversion rate. As a result of the Teton Transaction, in lieu of shares of the Company's common stock, holders of Trust Securities will receive $35.05 for each share of common stock it would have been entitled to receive on conversion.

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Distributions on the Trust Securities (and Junior Debentures) are cumulative, accrue from the date of initial issuance and are payable quarterly in arrears. The Junior Debentures are subordinated in right of payment to all senior indebtedness of the Company and the Junior Debentures are subject to certain covenants, events of default and optional and mandatory redemption provisions, all as described in the Junior Debenture indentures.

Pursuant to Preferred Securities Guarantee Agreements (collectively, the "Guarantees"), between the Company and a preferred guarantee trustee, the Company has agreed irrevocably to pay to the holders of the Trust Securities, to the extent that the Trustee has funds available to make such payments, quarterly distributions, redemption payments and liquidation payments on the Trust Securities. Considered together, the undertakings contained in the Declarations, Junior Debentures, Indentures and Guarantees constitute full and unconditional guarantees by the Company of the Trusts' obligations under the Trust Securities.

13.    Subsidiary-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust

On March 11, 2002, MidAmerican Energy redeemed all $100.0 million of its 7.98% MidAmerican-obligated preferred securities of subsidiary trust at 100% of the principal amount plus accrued interest.

14.    Preferred Securities of Subsidiaries

During 2002, MidAmerican Energy redeemed all $26.7 million of its $7.80 Series Preferred Shares.

The total outstanding cumulative preferred securities of MidAmerican Energy not subject to mandatory redemption requirements may be redeemed at the option of MidAmerican Energy at prices which, in the aggregate, total $32.6 million. The aggregate total the holders of all preferred securities outstanding at December 31, 2002, are entitled to upon involuntary bankruptcy is $31.8 million plus accrued dividends. Annual dividend requirements for all preferred securities outstanding at December 31, 2002, total $1.3 million.

The total outstanding 8.061% cumulative preferred securities of CE Electric UK, which are redeemable in the event of the revocation by the Secretary of State of the Company's Public Electricity Supply License, was $56.0 million as of December 31, 2002 and 2001.

15.    Convertible Preferred Stock

In connection with the Kern River acquisition and the purchase of $275.0 million of Williams' preferred stock, the Company issued 6.7 million shares of no par, zero-coupon convertible preferred stock valued at $402.0 million. In connection with the Teton Transaction, the Company issued 34.6 million shares of no par, zero coupon convertible preferred stock valued at $1,211.4 million. Each share of preferred stock is convertible at the option of the holder into one share of the Company's common stock subject to certain adjustments as described in the Company's Amended and Restated Articles of Incorporation.

16.    Stock Options

The Company had various stock option plans under which shares were reserved for grant as incentive or non-qualified stock options, as determined by the Board of Directors. The plans allowed options to be granted at 85% of their fair market value of the common stock at the date of grant. Generally, options were issued at 100% of fair market value of the common stock at the date of grant. Options remaining subsequent to the Teton Transaction became exercisable over a period of two to five years and expired if not exercised within ten years from the date of grant or, in some instances, a lesser term.

As a result of the Teton Transaction, the majority of the options were cashed out at $35.05 per share. The remaining options of 2,145,000 were reissued under the new MEHC and an additional 703,329 options were issued. The old options are fully vested and the additional options vest monthly over three years. The options are exercisable until the end of the term on March 14, 2008 at exercise prices ranging from $15.94 to $35.05 per share.

On March 6, 2002, the Company purchased stock options from Mr. David L. Sokol, its Chairman and Chief Executive Officer. The options purchased had exercise prices ranging from $18.50 to $29.01. The

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Company paid Mr. Sokol an aggregate amount of $27.1 million, which is equal to the difference between the option exercise prices and an agreed upon per share value.

17.    Accounting for Derivatives

MidAmerican Energy

Commodity Price Risk

Under the current regulatory framework, MidAmerican Energy is allowed to recover in revenue the cost of gas sold from all of its regulated gas customers through a purchased gas adjustment clause. Because the majority of MidAmerican Energy's firm natural gas supply contracts contain pricing provisions based on a daily or monthly market index, MidAmerican Energy's regulated gas customers, although ensured of the availability of gas supplies, retain the risk associated with market price volatility.

MidAmerican Energy uses natural gas futures, options and over-the-counter agreements to mitigate a portion of the market risk retained by its regulated gas customers through the purchased gas adjustment clause. These financial derivative instruments are identified and recorded as hedge transactions. The net amounts exchanged or accrued under swap agreements and the realized gains or losses on futures and options contracts are included in cost of sales and recovered in revenue from regulated gas customers.

MidAmerican Energy also derives revenue from nonregulated sales of natural gas. Pricing provisions are individually negotiated with these customers and may include fixed prices, prices based on a daily or monthly market index or prices based on MidAmerican Energy's actual costs. MidAmerican Energy enters into natural gas futures, options and swap agreements to offset the financial impact of variations in natural gas commodity prices for physical delivery to nonregulated customers. These financial derivative activities are also recorded as hedge accounting transactions.

MidAmerican Energy is exposed to variations in the price of fuel for generation and the price of purchased power in its Iowa jurisdiction, which comprises approximately 89% of 2002 electric operating revenues. Fuel price risk is mitigated through forward contracts. Under typical operating conditions, MidAmerican Energy has sufficient generation to supply its regulated retail electric needs. A loss of such generation at a time of high market prices could subject MidAmerican Energy to losses on its energy sales. MidAmerican Energy uses electricity forward contracts to hedge anticipated sales of excess wholesale electric power.

Derivative instruments are used for two types of hedges. Hedges that offset the variability in earnings and cash flows related to firm commitments are referred to as fair value hedges. Gains and losses on fair value hedges are recognized in income as either operating revenues or cost of sales, depending upon the nature of the item being hedged. Purchase and sales commitments hedged by fair value hedges are recorded at fair value, with changes in their fair values recognized in income and substantially offsetting the impact of the hedges on earnings. For 2002, net pre-tax unrealized gains (losses), representing the ineffectiveness of fair value hedges, were immaterial.

Hedges that offset the variability in earnings and cash flows related to forecasted transactions are referred to as cash flow hedges. The effective portion of unrealized gains and losses on cash flow hedges is recorded in other comprehensive income, net of associated deferred income taxes. Any ineffective portion of unrealized gains and losses on cash flow hedges is recognized in income as operating revenues or a cost of sales, depending upon the nature of the item being hedged. Only hedges that are highly effective in offsetting the risk of variability in future cash flows are accounted for in this manner. Forecasted transactions include purchases of gas for resale to regulated and nonregulated customers, purchases of gas for storage, and purchases and sales of wholesale electric energy. When the associated hedged forecasted transaction occurs or if a hedging relationship is no longer appropriate, the unrealized gains and losses are reversed from other comprehensive income and recognized in net income. Realized gains on cash flow hedges are recognized in income as either operating revenues or cost of sales, depending upon the nature of the physical transaction being hedged.

For 2002, net pre-tax unrealized gains (losses) of $13,000 and $502,000, representing the ineffectiveness of cash flow hedges, are reflected in operating revenues and cost of sales, respectively, on the consolidated

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statements of operations. During the twelve months beginning January 1, 2003, it is anticipated that all of the after-tax, net unrealized gains on cash flow hedges presently recorded as accumulated other comprehensive income will be realized and recorded in earnings. MidAmerican Energy has hedged a portion of its exposure to the variability of cash flows for forecasted transactions through December 2003.

At December 31, 2002, MidAmerican Energy held derivative instruments used for the following hedging purposes with the following fair values (in thousands):


Type Maturity in
2003		 Maturity in
2004-06		 Total
Regulated electric $ 1,018   $ 112   $ 1,130  
Regulated gas   1,150     —     1,150  
Nonregulated gas   2,027     (41 )    1,986  
Total $ 4,195   $ 71   $ 4,266  

A $5.00 per MWh increase in the price of electricity would decrease the fair value of electric hedge instruments by $316,000. A $1.00 per MMBtus increase in the price of natural gas would increase the fair value of gas hedge instruments by $2.3 million.

Trading Risk

MidAmerican Energy uses natural gas and electricity derivative instruments and forward contracts for proprietary trading purposes under strict guidelines outlined by senior management. Derivative instruments held for trading purposes are recorded at fair value and any unrealized gains or losses are reported in earnings.

MidAmerican Energy uses value at risk, or VaR calculations to measure and control its exposure to market risk sensitive instruments. VaR is an estimate of the potential loss on a portfolio over a specified holding period, based on normal market conditions and within a given statistical confidence interval. MidAmerican Energy calculates VaR separately for its electric and gas proprietary trading activities based on a variance-covariance method using historical prices to estimate volatilities and correlations, a one-day holding period and a 95% level of confidence. MidAmerican Energy initiated its nonregulated proprietary electric trading activities in early 2002. Accordingly, the following summary of MidAmerican Energy's trading VaR profile for 2001 includes only gas trading data.


  VaR (in $millions)
  2002 2001
At December 31 $ 0.3   $ 0.2  
High during year   0.5     0.3  
Low during year   0.1     —  
Average during year   0.2     0.1  

The fair value of MidAmerican Energy's proprietary trading activities at December 31, 2002 and the periods in which unrealized gains and losses are expected to be realized are as follows (in thousands):


Type Maturity in
2003		 Maturity in
2004-06		 Total
Exchange prices $ 4,683   $ 71   $ 4,754  
Prices actively quoted   (4,259 )    (159 )    (4,418 ) 
Prices based on models   207     (14 )    193  
Total $ 631   $ (102 )  $ 529  

CE Electric UK

Currency Exchange Rate Risk

CE Electric UK entered into certain currency rate swap agreements for the CE Electric UK Company Senior Notes with two large multi-national financial institutions. The swap agreements effectively convert

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the U.S. dollar fixed interest rate to a fixed rate in Sterling. For the $125.0 million of 6.853% Senior Notes, the agreements extend until maturity on December 30, 2004 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.744%. For the $237.0 million of 6.995% Senior Notes, the agreements extend until maturity on December 30, 2007 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.737%. The estimated fair value of these swap agreements at December 31, 2002 is approximately $24.5 million based on quotes from the counterparty to these instruments and represents the estimated amount that the Company would expect to receive if these agreements were terminated.

Yorkshire entered into certain currency rate swap agreements for the Trust Securities and the Yankee Bonds with five large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in Sterling. For the 8.08% Trust Securities, the agreements extend until June 30, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 9.4758% to 9.715%. For the $300.0 million of 6.496% Yankee Bonds, the agreements extend until February 25, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 7.3175% to 7.345%. The estimated fair value of these swap agreements at December 31, 2002 is approximately $(22.8) million based on quotes from the counterparty to these instruments and represents the estimated amount that the Company would expect to pay if these agreements were terminated.

A decrease of 10% in the December 31, 2002 rate of exchange of Sterling to dollars would increase the amount paid to the Company if these swap agreements were terminated by approximately $120.9 million.

Northern Natural Gas

Commodity Price Risk

As of December 31, 2002, Northern Natural Gas had $52.0 million of obligations to deliver 12.2 Bcf of natural gas in 2003. The obligations are revalued based on market prices for natural gas, with changes in value included in the statement of operations. In 2002, Northern Natural Gas entered into natural gas commodity price swaps and index basis swaps to effectively fix the deferred obligation balance. These swaps have a net receivable balance of $3.4 million at December 31, 2002. The swaps are revalued based on market prices for natural gas, with changes in value included in the statement of operations. Therefore, any further changes in the market value of the deferred obligations are expected to be offset by a corresponding change in the opposite direction in the market value of the swaps. However, at December 31, 2002, Northern Natural Gas had a $10.4 million receivable position with a third party energy marketer relating to these swaps. Since the date of entering into these swaps, there have been public announcements that this third party's financial condition has deteriorated as a result of, among other factors, reduced liquidity. This receivable would increase by approximately $12.2 million if the price curve of natural gas were to increase by $1.00 per MMBtu from levels at December 31, 2002. The Company has not recorded an allowance on this receivable as of December 31, 2002, and is monitoring the situation.

18.    Regulatory Matters

MidAmerican Energy

Under a settlement agreement approved by the IUB on December 21, 2001, MidAmerican Energy's Iowa retail electric rates in effect on December 31, 2000, are effectively frozen through December 31, 2005. In approving that settlement, the IUB specifically allows the filing of electric rate design and/or cost of service rate changes that are intended to keep overall company revenues unchanged but could result in changes to individual tariffs. Under the 2001 settlement agreement, an amount equal to 50% of revenues associated with Iowa retail electric returns on equity between 12% and 14%, and 83.33% of revenues associated with Iowa retail electric returns on equity above 14%, in each year is recorded as a regulatory liability to be used to offset a portion of the cost to Iowa customers of future generating plant investments. An amount equal to the regulatory liability is recorded as a regulatory charge in depreciation and amortization expense when the liability is accrued. Interest expense is accrued on the portion of the regulatory liability related to prior years. Beginning in 2002, the liability is being relieved as it is credited against allowance for funds used during construction, or capitalized financing costs, associated with generating plant additions. As of December 31, 2002, the related liability reflected on the consolidated balance sheet totaled $102.9 million.

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On March 20, 2003, MidAmerican Energy and the Iowa Office of Consumer Advocate agreed upon a settlement proposal in which the rate freeze described above would be extended through December 31, 2010. Under the settlement proposal, for calendar years 2006 through 2010, an amount equal to 40% of revenues associated with Iowa retail electric returns on equity between 11.75% and 13.0%; 50% of revenues associated with Iowa retail electric returns on equity between 13.0% and 14.0%; and 83.3% of revenues associated with Iowa retail electric returns on equity greater than 14.0% will be applied as a reduction to offset some of the capital costs on the Iowa portion of three generation projects. If Iowa retail electric returns on equity fall below 10% in any 12-month period after January 1, 2006, MidAmerican Energy has the ability to file for a general increase in rates under the proposed settlement. The proposed settlement requires enactment of Iowa legislation and is subject to approval by the IUB. The IUB is expected to rule on the proposal during the second half of 2003.

On March 15, 2002, MidAmerican Energy made a filing with the IUB requesting an increase in rates for its Iowa retail natural gas customers. On June 12, 2002, the IUB issued an order granting an interim rate increase of approximately $13.8 million annually, effective immediately and subject to refund with interest. On November 8, 2002, the IUB approved the proposed settlement agreement previously filed with it by MidAmerican Energy and the Iowa Office of Consumer Advocate. The settlement agreement provides for an increase in rates of $17.7 million annually for MidAmerican Energy's Iowa retail natural gas customers and effectively freezes such rates through November 2004. MidAmerican Energy implemented the new rates for usage beginning November 25, 2002.

CE Electric UK

Most revenue of each Distribution License Holder ("DLH") is controlled by a distribution price control formula. The current formula requires that regulated distribution income per unit is increased or decreased each year by RPI-Xd where the Retail Price Index ("RPI") reflects the average of the 12-month inflation rates recorded for each month in the previous July to December period. The distribution price control formula also reflects an adjustment factor ("Xd") which was established by the regulatory body, the Office of Gas and Electricity Markets ("Ofgem"), at the last price control review (and continues to be set) at 3%. The formula also takes account of the changes in system electrical losses, the number of customers connected and the voltage at which customers receive the units of electricity distributed. This formula determines the maximum average price per unit of electricity distributed (in pence per kWh) which a DLH is entitled to charge. The distribution price control formula permits DLHs to receive additional revenue due to increased distribution of units and a predetermined increase in customer numbers. The price control does not seek to constrain the profits of a DLH from year to year. It is a control on revenue that operates independently of most of the DLH's costs. During the lifetime of the price control, cost savings or additional costs have a direct impact on profit.

19.    Pension Commitments

Domestic Operations

The Company has primarily noncontributory defined benefit pension plans covering substantially all domestic employees. Benefit obligations under the plans are based on participants' compensation, years of service and age at retirement. Funding is based upon the actuarially determined costs of the plans and the requirements of the Internal Revenue Code and the Employee Retirement Income Security Act.

The Company currently provides certain postretirement health care and life insurance benefits for retired employees. Under the plans, substantially all of the Company's employees may become eligible for these benefits if they reach retirement age while working for the Company. However, the Company retains the right to change these benefits anytime at its discretion.

The Company also maintains noncontributory, nonqualified supplemental executive retirement plans for active and retired participants.

Net periodic pension, supplemental retirement and postretirement benefit costs for domestic employees included the following components for the Company (in thousands):

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  Year Ended
December 31,		 March 14, 2000
through
December 31, 2000		 MEHC
(Predecessor)
January 1, 2000
through
March 13, 2000
  2002 2001
Pension Cost:
Service cost $ 20,235   $ 18,114   $ 13,014   $ 3,242  
Interest cost   34,177     33,027     28,329     7,058  
Expected return on plan assets   (38,213 )    (36,326 )    (38,532 )    (9,600 ) 
Amortization of net transition obligation   (2,591 )    (2,591 )    (2,074 )    (517 ) 
Amortization of prior service cost   2,729     2,729     2,310     575  
Amortization of prior year gain   (2,482 )    (3,894 )    (3,297 )    (822 ) 
Regulatory expense   6,639     —     —     —  
Net periodic pension cost (benefit) $ 20,494   $ 11,059   $ (250 )  $ (64 ) 

  Year Ended
December 31,		 March 14, 2000
through
December 31, 2000		 MEHC
(Predecessor)
January 1, 2000
through
March 13, 2000
  2002 2001
Postretirement Cost:
Service cost $ 6,028   $ 4,357   $ 2,089   $ 520  
Interest cost   13,928     10,418     6,688     1,666  
Expected return on plan assets   (4,880 )    (4,032 )    (3,947 )    (984 ) 
Amortization of net transition obligation   4,110     4,110     3,290     820  
Amortization of prior service cost   425     425     340     85  
Amortization of prior year (gain) loss   2,385     332     (699 )    (174 ) 
Net periodic pension cost $ 21,996   $ 15,610   $ 7,761   $ 1,933  

The pension plan assets are in external trusts and are comprised of corporate equity securities, United States government debt, corporate bonds and insurance contracts. The postretirement benefit plans assets are in external trusts and are comprised primarily of corporate equity securities, corporate bonds, money market investment accounts and municipal bonds.

Although the supplemental executive retirement plans had no plan assets as of December 31, 2002, MidAmerican Energy has Rabbi trusts which hold corporate-owned life insurance and other investments to provide funding for the future cash requirements. Because these plans are nonqualified, the fair value of these assets is not included in the following table. The fair value of the Rabbi trust investments was $52.8 million and $50.4 million at December 31, 2002 and 2001, respectively.

The following table presents a reconciliation of the beginning and ending balances of the benefit obligation, fair value of plan assets and the funded status of the Company's plans to the net amounts recognized in the consolidated balance sheet as of December 31 (in thousands):

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  Pension
Benefits		 Postretirement
Benefits
  2002 2001 2002 2001
Reconciliation of benefit obligation:
Benefit obligation at beginning of year $ 518,208   $ 472,349   $ 194,917   $ 131,822  
Service cost   20,235     18,114     6,028     4,357  
Interest cost   34,177     33,027     13,928     10,418  
Participant contributions   —     —     4,505     3,059  
Plan amendments   —     652     —     —  
Actuarial (gain) loss   45,461     17,333     31,743     57,101  
Acquisition   520     —     55,305     —  
Benefits paid   (25,422 )    (23,267 )    (14,985 )    (11,840 ) 
Benefit obligation at end of year   593,179     518,208     291,441     194,917  
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year   515,890     555,208     81,129     75,090  
Employer contributions   4,681     4,576     24,034     16,022  
Participant contributions   —     —     4,505     3,059  
Actual return on plan assets   (27,376 )    (20,627 )    (4,528 )    (1,202 ) 
Acquisition   —     —     32,500     —  
Benefits paid   (25,422 )    (23,267 )    (14,985 )    (11,840 ) 
Fair value of plan assets at end of year   467,773     515,890     122,655     81,129  
Funded status   (125,406 )    (2,318 )    (168,786 )    (113,788 ) 
Unrecognized net (gain) loss   61,289     (52,244 )    102,095     63,328  
Unrecognized prior service cost   20,156     22,885     3,838     4,264  
Unrecognized net transition obligation (asset)   (3,383 )    (5,974 )    41,102     45,212  
Net amount recognized in the consolidated balance sheet $ (47,344 )  $ (37,651 )  $ (21,751 )  $ (984 ) 
Amounts recognized in the consolidated balance
sheet consist of:
Prepaid benefit cost $ 11,305   $ 15,381   $ 1,494   $ 1,493  
Accrued benefit liability   (99,392 )    (88,210 )    (23,245 )    (2,477 ) 
Intangible asset   20,082     22,796     —     —  
Accumulated other comprehensive income   20,661     12,382     —     —  
Net amount recognized $ (47,344 )  $ (37,651 )  $ (21,751 )  $ (984 ) 

Pension and Postretirement Assumptions are as follows for the years ended December 31:


  2002 2001 2000
Assumptions used were:
Discount rate   5.75 %    6.50 %    7.00 % 
Rate of increase in compensation levels   5.00 %    5.00 %    5.00 % 
Weighted average expected long-term rate of return on assets   7.00 %    7.00 %    9.00 % 

For purposes of calculating the postretirement benefit obligation, it is assumed health care costs for all covered individuals will increase by 9.75% in 2003 and that the rate of increase thereafter will decrease to an ultimate rate of 5.25% by the year 2007.

If the assumed health care trend rates used to measure the expected cost of benefits covered by the plans were increased by 1.0%, the total service and interest cost for 2002 would increase by $4.1 million, and the

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postretirement benefit obligation at December 31, 2002, would increase by $47.5 million. If the assumed health care trend rates were to decrease by 1.0%, the total service and interest cost for 2002 would decrease by $3.1 million and the postretirement benefit obligation at December 31, 2002, would decrease by $37.0 million.

United Kingdom Operations

CE Electric UK participates in the Electricity Supply Pension Scheme, which provides pension and other related defined benefits, based on final pensionable pay, to substantially all employees throughout the Electricity Supply Industry in the United Kingdom.

The actuarial computation for December 31, 2002, 2001 and 2000 assumed interest rates of 5.75%, 5.75% and 6.0% respectively, an expected return on plan assets of 7.0%, 7.0% and 6.5%, respectively, and annual compensation increases of 2.5%, 2.5% and 3.0%, respectively, over the remaining service lives of employees covered under the plan. Amounts funded to the pension are primarily invested in equity and fixed income securities.

Net periodic pension cost (benefit) for CE Electric UK's plan for 2002, 2001 and 2000 included the following components (in thousands):


  Year Ended
December 31,		 March 14, 2000
through
December 31, 2000		 MEHC
(Predecessor)
January 1, 2000
through
March 13, 2000
  2002 2001
Service cost – benefits earned during the period $ 8,718   $ 7,781   $ 6,933   $ 1,727  
Interest cost on projected benefit obligation   56,817     51,440     40,640     10,125  
Expected return on plan assets   (85,927 )    (78,354 )    (50,800 )    (12,657 ) 
Amortization of prior service cost   1,202     —     —     —  
Curtailment loss   6,463     7,061     5,260     1,310  
Net periodic pension (benefit) cost $ (12,727 )  $ (12,072 )  $ 2,033   $ 505  

As a result of the distribution price reviews in 1999, CE Electric UK implemented a review of staffing requirements primarily in its distribution business. Following discussions with the trade unions, CE Electric UK put in place a workforce reduction program. The pension curtailment related to this workforce reduction program was $6.9 million, $7.1 million and $6.6 million in 2002, 2001 and 2000, respectively.

The following table details the funded status and the amount recognized in the Company's consolidated balance sheets for CE Electric UK's plan as of December 31, 2002 and 2001 (in thousands):

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  2002 2001
Change in benefit obligation:
Benefit obligation at beginning of year $ 974,079   $ 951,553  
Service cost   8,718     7,781  
Interest cost   56,817     51,440  
Participant contributions   3,006     5,187  
Benefits paid   (57,719 )    (48,991 ) 
FAS 88 curtailment   5,712     7,060  
Northern Supply/Yorkshire swap net effect   —     43,803  
Prior service cost   17,286     —  
Experience gain and change of assumptions   (11,574 )    (19,596 ) 
Foreign currency exchange rate changes   106,405     (24,158 ) 
Benefit obligation at end of the year   1,102,730     974,079  
Change in plan assets:
Fair value of plan assets at beginning of the year   1,070,657     1,166,111  
Actual return on plan assets   (144,298 )    (68,010 ) 
Net asset transfer resulting from Northern Supply/Yorkshire Swap   —     46,541  
Employer contributions   3,607     576  
Participant contributions   3,006     5,187  
Benefits paid   (57,719 )    (48,991 ) 
Foreign currency exchange rate changes   101,174     (30,757 ) 
Fair value of plan assets at end of the year   976,427     1,070,657  
Funded status   (126,303 )    96,578  
Unrecognized net loss   465,211     196,649  
Net amount recognized in the consolidated balance sheet $ 338,908   $ 293,227  
Amounts recognized in the consolidated balance sheetconsist of:
Prepaid benefit cost $ 338,908   $ 293,227  
Accrued benefit liability   (457,317 )    —  
Intangible asset   16,433     —  
Accumulated other comprehensive income   440,884     —  
Net amount recognized $ 338,908   $ 293,227  

20.    Commitments and Contingencies

Manufactured Gas Plants

The United States Environmental Protection Agency ("EPA"), and the state environmental agencies have determined that contaminated wastes remaining at decommissioned manufactured gas plant facilities may pose a threat to the public health or the environment if such contaminants are in sufficient quantities and at such concentrations as to warrant remedial action.

MidAmerican Energy has evaluated or is evaluating 27 properties that were, at one time, sites of gas manufacturing plants in which it may be a potentially responsible party. The purpose of these evaluations is to determine whether waste materials are present, whether the materials constitute an environmental or health risk, and whether MidAmerican Energy has any responsibility for remedial action. As of December 31, 2002, MidAmerican Energy has recorded a $17 million liability for these sites and a corresponding regulatory asset for future recovery through the regulatory process.

Although the timing of potential incurred costs and recovery of costs in rates may affect the results of operations in individual periods, management believes that the outcome of these issues will not have a material adverse effect on MidAmerican Energy's financial position or results of operations.

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Air Quality

In July 1997, the EPA adopted revisions to the National Ambient Air Quality Standards for ozone and a new standard for fine particulate matter. In February 2001, the United States Supreme Court upheld the constitutionality of the standards, though remanding the issue of implementation of the ozone standard to the EPA. The impact of the new standards on MidAmerican Energy is currently unknown. These standards could be superceded, in whole or in part, by a variety of multi-pollutant emission reduction initiatives.

In 2001, the state of Iowa passed legislation that, in part, requires rate-regulated utilities to develop a multi-year plan and budget for managing regulated emissions from their generating facilities in a cost-effective manner. MidAmerican Energy's proposed plan and associated budget (the "Plan") was filed with the IUB on April 1, 2002, in accordance with state law. MidAmerican Energy expects the IUB to rule on the prudence of the Plan in 2003. MidAmerican Energy is required to file Plan updates at least every two years.

The Plan provides MidAmerican Energy's projected air emission reductions considering the current proposals that are being debated at the federal level and describes a coordinated long-range plan to achieve these air emission reductions. The Plan also provides specific actions to be taken at each coal-fired generating facility and the related costs and timing for each action.

The Plan outlines $732.0 million in environmental investments to existing coal-fired generating units, some of which are jointly owned, over a nine-year period from 2002 through 2010. MidAmerican Energy's share of these investments is $546.6 million, $67.9 million of which was projected to be incurred in the years 2002 through 2005, when MidAmerican Energy's Iowa retail electric rates are effectively frozen. The Plan also identifies expenses that will be incurred at the generating facilities to operate and maintain the environmental equipment installed as a result of the Plan.

Following the expiration of MidAmerican Energy's 2001 settlement agreement on December 31, 2005, the Plan proposes the use of an adjustment mechanism for recovery of Plan costs, similar to the tracking mechanisms for cost recovery of renewable energy and energy efficiency expenditures that are presently part of MidAmerican Energy's regulated electric rates.

Under the New Source Review ("NSR"), provisions of the Clean Air Act ("CAA"), a utility is required to obtain a permit from the EPA prior to (1) beginning construction of a new major stationary source of a NSR-regulated pollutant or (2) making a physical or operational change (a "major modification") to an existing facility that potentially increases emissions, unless the changes are exempt under the regulations. In general, projects subject to NSR regulations are subject to pre-construction review and permitting under the Prevention of Significant Deterioration ("PSD"), provisions of the CAA. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo a Best Available Control Technology analysis and evaluate the most effective emissions controls. These controls must be installed in order to receive a permit. Routine maintenance, repair and replacement are not subject to the NSR provisions; however, these types of activities have historically been subject to changing interpretations under the NSR program. The EPA recently proposed a change to the NSR provisions relating to routine maintenance, repair and replacement. Violation of NSR regulations potentially subjects a utility to fines and/or other sanctions. The impact on MidAmerican Energy of any final rules is not currently known.

In recent years, the EPA has requested from several utilities information and support regarding their capital projects for various generating plants. The requests were issued as part of an industry-wide investigation to assess compliance with the NSR and the New Source Performance Standards of the CAA. In December 2002, MidAmerican Energy received a request from the EPA to provide documentation related to its capital projects from January 1, 1980, to the present for its Neal, Council Bluffs, Louisa and Riverside Energy Centers. MidAmerican Energy has responded to this request and at this time cannot predict the outcome of request.

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Decommissioning Costs

Expected decommissioning costs for Quad Cities Station have been developed based on a site-specific decommissioning study that includes decontamination, dismantling, site restoration, dry fuel storage cost and an assumed shutdown date. Quad Cities Station decommissioning costs are included in as base rates in Iowa tariffs.

MidAmerican Energy's share of expected decommissioning costs for Quad Cities Station, in 2002 dollars, is $266 million. MidAmerican Energy has established external trusts for the investment of funds for decommissioning the Quad Cities Station. The total accrued balance as of December 31, 2002, was $159.8 million and is included in other liabilities. A like amount is reflected in properties, plants and equipment and represents the fair value of the assets held in the trusts.

MidAmerican Energy's depreciation expense included costs for Quad Cities Station nuclear decommissioning of $8.3 million for each of the years 2002, 2001 and 2000. The provision charged to depreciation expense is equal to the funding that is being collected in Iowa rates. The decommissioning funding component of MidAmerican Energy's Iowa tariff assumes decommissioning costs, related to the Quad Cities Station, will escalate at an annual rate of 5.0% and the assumed annual return on funds in the trust is 6.9%. Income (loss), net of investment fees, on the assets in the trust fund increase/(decrease) by a comparable amount MidAmerican Energy's decommissioning liability. Actual amounts were $(6.9) million, $(3.1) million and $3.2 million for 2002, 2001 and 2000, respectively.

Nuclear Insurance

MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station through a combination of insurance purchased by Exelon Generation Company, LLC ("Exelon Generation"), the operator and joint owner of Quad Cities Station, insurance purchased directly by MidAmerican Energy, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988. The general types of coverage are: nuclear liability, property coverage and nuclear worker liability.

Exelon Generation purchases nuclear liability insurance for Quad Cities Station in the maximum available amount of $200 million. In accordance with the Price-Anderson Amendments Act of 1988, excess liability protection above that amount is provided by a mandatory industry-wide Secondary Financial Protection program under which the licensees of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the United States. Currently, MidAmerican Energy's aggregate maximum potential share of an assessment for Quad Cities Station is approximately $44 million per incident, payable in installments not to exceed $5 million annually.

The property insurance covers for property damage, stabilization and decontamination of the facility, disposal of the decontaminated material and premature decommissioning arising out of a covered loss. For Quad Cities Station, Exelon Generation purchased primary and excess property insurance protection for the combined interests in Quad Cities Station, with coverage limits totaling $2.1 billion. MidAmerican Energy also directly purchased extra expense/business interruption coverage for its share of replacement power and/or other extra expenses in the event of a covered accidental outage at Quad Cities Station. The property and related coverages purchased directly by MidAmerican Energy and by Exelon Generation, which includes the interests of MidAmerican Energy, are underwritten by an industry mutual insurance company and contain provisions for retrospective premium assessments should two or more full policy-limit losses occur in one policy year. Currently, the maximum retrospective amounts that could be assessed against MidAmerican Energy from industry mutual policies for its obligations associated with Quad Cities Station total $6.3 million.

The master nuclear worker liability coverage, which is purchased by Exelon Generation for Quad Cities Station, is an industry-wide guaranteed-cost policy with an aggregate limit of $200 million for the nuclear industry as a whole, which is in effect to cover tort claims in nuclear-related industries.

Fuel, Energy and Operating Lease Commitments

MidAmerican Energy has supply and related transportation contracts for its fossil fueled generating stations. The contracts, with expiration dates ranging from 2003 to 2007, require minimum payments of

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$76.4 million, $61.2 million, $43.6 million, $2.6 million and $2.6 million for the years 2003 through 2007, respectively. MidAmerican Energy expects to supplement these coal contracts with additional contracts and spot market purchases to fulfill its future fossil fuel needs.

MidAmerican Energy also has contracts with non-affiliated companies to purchase electric capacity. The contracts, with expiration dates ranging from 2003 to 2028, require minimum payments of $40.2 million, $37.8 million, $2.9 million, $2.2 million and $2.2 million for the years 2003 through 2007, respectively, and $45.6 million for the total of the years thereafter.

MidAmerican Energy has various natural gas supply and transportation contracts for its gas operations. The minimum commitments under these contracts are $51.9 million, $46.8 million, $37.2 million, $13.1 million and $10.2 million for the years 2003 through 2007, respectively, and $16.6 million for the total of the years thereafter.

HomeServices is the lessee on operating leases primarily for office space for its various brokerage offices. The minimum payments under these leases are $36.0 million, $30.1 million, $25.7 million, $22.4 million and $17.9 million for the years 2003 through 2007, respectively, and $40.7 million for the total of the years thereafter.

MidAmerican Energy, Kern River, Northern Natural Gas and CE Electric UK have various non-cancelable operating leases primarily for office space and rail cars. The minimum payments under these leases are $24.8 million, $16.9 million, $12.7 million, $10.6 million and $9.4 million for the years 2003 through 2007, respectively, and $46.0 million for the total of the years thereafter.

MidAmerican Energy is the lessee on operating leases for coal railcars that contain guarantees of the residual value of such equipment throughout the term of the leases. Events triggering the residual guarantees include termination of the lease, loss of the equipment or purchase of the equipment. Lease terms are for five years with provisions for extensions. At December 31, 2002, the maximum amount of such guarantees specified in these leases totals $31.5 million.

Pipeline Litigation

In 1998, the United States Department of Justice informed the then current owners of Kern River and Northern Natural Gas that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against such entities and certain of their subsidiaries including Kern River and Northern Natural Gas. Mr. Grynberg has also filed claims against numerous other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties allegedly not paid to the federal government, treble damages, civil penalties, attorneys' fees and costs. On April 9, 1999, the United States Department of Justice announced that it declined to intervene in any of the Grynberg qui tam cases, including the actions filed against Kern River and Northern Natural Gas in the United States District Court for the District of Colorado. On October 21, 1999, the Panel on Multi-District Litigation transferred the Grynberg qui tam cases, including the ones filed against Kern River and Northern Natural Gas, to the United States District Court for the District of Wyoming for pre-trial purposes. Motions to dismiss the complaint, filed by various defendants including Northern Natural Gas and Williams, which was the former owner of Kern River, were denied on May 18, 2001. On October 9, 2002, the United States District Court for the District of Wyoming dismissed Grynberg's Royalty Valuation Claims. Grynberg has appealed this dismissal to the United States Court of Appeals for the Tenth Circuit. In connection with the purchase of Kern River from Williams in March 2002, Williams agreed to indemnify the Company against any liability for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. No such indemnification was obtained in connection with the purchase of Northern Natural Gas in August 2002. The Company believes that the Grynberg cases filed against Kern River and Northern Natural Gas are without merit and Williams, on behalf of Kern River pursuant to its indemnification, and Northern Natural Gas, intend to defend these actions vigorously.

On June 8, 2001, a number of interstate pipeline companies, including Kern River and Northern Natural Gas, were named as defendants in a nationwide class action lawsuit which had been pending in the 26th Judicial District, District Court, Stevens County Kansas, Civil Department against other defendants,

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generally pipeline and gathering companies, since May 20, 1999. The plaintiffs allege that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs. In November 2001, Kern River and Northern Natural Gas, along with the coordinating defendants, filed a motion to dismiss under Rules 9B and 12B of the Kansas Rules of Civil Procedure. In January 2002, Kern River and most of the coordinating defendants filed a motion to dismiss for lack of personal jurisdiction. The court has yet to rule on these motions. The plaintiffs filed for certification of the plaintiff class on September 16, 2002. On January 13, 2003, oral arguments were heard on coordinating defendants' opposition to class certification. On April 10, 2003, the court entered an order denying the plaintiffs' motion for class certification. It is anticipated that the plaintiffs will appeal this decision. Williams has agreed to indemnify the Company against any liability associated with Kern River for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. Williams, on behalf of Kern River and other entities, anticipates joining with Northern Natural Gas and other defendants in contesting certification of the plaintiff class. Kern River and Northern Natural Gas believe that this claim is without merit and that Kern River's and Northern Natural Gas' gas measurement techniques have been in accordance with industry standards and its tariff.

Kern River's 2003 Expansion Project

The 2003 Expansion Project is a new parallel 717-mile loop pipeline that will begin in Lincoln County, Wyoming and terminate in Kern County, California. The 2003 Expansion Project began construction on August 6, 2002 and is expected to be completed and operational by May 1, 2003 at a total cost of approximately $1.2 billion. The 2003 Expansion Project is being financed with approximately 70% debt and 30% equity, consistent with Kern River's original capital structure, the application for the FERC approval described above and the limitations contained in the indenture for Kern River's existing secured senior notes.

Construction is being initially funded with the proceeds of an $875.0 million facility entered into by Kern River on June 21, 2002, for approximately 70% of the projected capitalized costs of the 2003 Expansion Project. The remaining approximately 30% of the capitalized costs of the 2003 Expansion Project is being funded with equity from the Company. The credit facility is structured as a two-year construction facility followed by a term loan with a final maturity 15 years after completion of the 2003 Expansion Project. However, Kern River presently intends to refinance the construction financing facility through a bond offering or other capital markets transaction following completion of the 2003 Expansion Project. Prior to completion of the 2003 Expansion Project, the holders of the construction financing facility will have limited recourse to Kern River and its assets and cash flow, and will have recourse to the Company's completion guarantee described below. Following completion of the 2003 Expansion Project, until such time as the Kern River construction financing facility is refinanced, the lenders under the construction financing facility will share equally and ratably with the existing holders of Kern River's senior Notes in all of the collateral pledged to such Senior Note holders.

Pursuant to the Company's completion guarantee, it has guaranteed that "completion" of the 2003 Expansion Project will occur on or prior to the earliest of any abandonment by Kern River of the project, the occurrence of certain other acceleration events and June 30, 2004. The potential acceleration events include any downgrading of the Company's public debt rating to below investment grade by either S&P or Moody's unless a satisfactory substitute guarantor assumes the Company's obligations under the completion guarantee within 60 days after any such downgrade; Berkshire Hathaway ceasing to own at least a majority of the outstanding capital stock of the Company; and certain other customary events of default by the Company. In the completion guarantee, the Company has also agreed to cause capital contributions to be made to Kern River in a minimum aggregate amount of at least $375 million by June 30, 2004 or upon any earlier event of abandonment of the project. For purposes of the Company's completion guarantee, the term "completion" is defined in the Kern River construction financing agreement to mean satisfaction of a number of conditions, the most significant of which include the requirements that the 2003 Expansion Project be substantially complete and operable and able to permit Kern River to perform its obligations under all of the long-term firm gas transportation service agreements entered into in connection with the 2003 Expansion Project; that the shippers under such agreements shall have begun to incur the obligation to pay reservation fees thereunder; and that the

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FERC shall have authorized Kern River to begin collecting rates under its tariff and its shipper agreements; provided that the 2003 Expansion Project shall still be deemed to have been completed if it is less than substantially complete but it demonstrates at least 80% design capacity and Kern River's debt service coverage ratios as defined in its Senior Notes indenture are not less than 1:55 to 1:0. There are a number of other conditions to completion, including requirements that all conditions to completion of the expansion contained in Kern River's Senior Notes indenture be satisfied and all of Kern River's obligations under its construction financing agreement then share pari passu in all collateral available to Kern River's senior secured noteholders. The Company's completion guarantee shall terminate upon the earlier of completion of the 2003 Expansion Project or repayment in full of all obligations under the Kern River credit facility.

Philippines

Casecnan Construction Arbitration

On February 12, 2001, the contractor filed a Request for Arbitration with the International Chamber of Commerce seeking schedule relief of up to 153 days through August 31, 2001 resulting from various alleged force majeure events. In its March 20, 2001 Supplement to Request for Arbitration, the contractor requested compensation for alleged additional costs of approximately $4 million it incurred from the claimed force majeure events to the extent it is unable to recover from its insurer. On April 20, 2001, the contractor filed a further supplement seeking an additional compensation for damages of approximately $62 million for the alleged force majeure event (and geologic conditions) related to the collapse of the surge shaft. The contractor also has alleged that the circumstances in which CE Casecnan assumed control of the Casecnan Project and placed it into commercial operation on December 11, 2001 amounted to a repudiation of the construction contract and has filed a claim for unspecified quantum meruit damages, and has further alleged that the delay liquidated damages clause which provides for payments of $125,000 per day for each day of delay in completion of the Project for which the contractor is responsible is unenforceable. The arbitration is being conducted applying New York law and in accordance with the rules of the International Chamber of Commerce.

Hearings have been held in connection with this arbitration in July 2001, September 2001, January 2002, March 2002, November 2002 and January 2003. As part of those hearings, on June 25, 2001, the arbitration tribunal temporarily enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di Roma in support of the contractor's obligations to CE Casecnan for delay liquidated damages. As a result of the continuing nature of that injunction, on April 26, 2002, CE Casecnan and the contractor mutually agreed that no demands would be made on the Banca di Roma demand guaranty except pursuant to an arbitration award. As of December 31, 2002, however, CE Casecnan has received approximately $6.0 million of liquidated damages from demands made on the demand guarantees posted by a separate financial institution on behalf of the contractor. On November 7, 2002, the International Chamber of Commerce issued the arbitration tribunal's partial award with respect to the contractor's force majeure and geologic conditions claims. The arbitration panel awarded the contractor 18 days of schedule relief in the aggregate for all of the force majeure events and awarded the contractor $3.8 million with respect to the cost of the collapsed surge shaft. The $3.8 million is shown as part of the accounts payable and accrued expenses balance at the end of December 31, 2002. All of the contractor's other claims with respect to force majeure and geologic conditions were denied.

Further hearings on the contractor's repudiation and quantum meruit claims, the alleged unenforceability of the delay liquidated damages clause and certain other matters had been scheduled for March 24 through March 28, 2003, but were postponed as a result of the commencement of military action in Iraq. The arbitral tribunal has requested the parties to indicate the earliest possible date on which they are available and will then reschedule the hearings.

If the contractor were to prevail on its claim that the delay liquidated damages clause is unenforceable, CE Casecnan would not be entitled to collect such delay damages for the period from March 31, 2001 through December 11, 2001. If the contractor were to prevail in its repudiation claim and prove quantum meruit damages in excess of amounts already paid to the contractor, CE Casecnan could be liable to make additional payments to the contractor. CE Casecnan believes all such allegations and claims are without merit and is vigorously contesting the contractor's claims.

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Casecnan NIA Arbitration

Under the terms of the Project Agreement, NIA has the option of timely reimbursing CE Casecnan directly for certain taxes CE Casecnan has paid. If NIA does not so reimburse CE Casecnan, the taxes paid by CE Casecnan result in an increase in the Water Delivery Fee. The payment of certain other taxes by CE Casecnan results automatically in an increase in the Water Delivery Fee. As of December 31, 2002, CE Casecnan has paid approximately $56.7 million in taxes which as a result of the foregoing provisions has resulted in an increase in the Water Delivery Fee. NIA has failed to pay the portion of the Water Delivery Fee each month which relates to the payment of these taxes by CE Casecnan. As a result of this non-payment, on August 19, 2002, CE Casecnan filed a Request for Arbitration against NIA, seeking payment of such portion of the Water Delivery Fee and enforcement of the relevant provision of the Project Agreement going forward. The arbitration will be conducted in accordance with the rules of the International Chamber of Commerce. NIA is expected to file its answer late in the first quarter or early in the second quarter, 2003. The three member arbitration panel has been confirmed by the International Chamber of Commerce and an initial organizational hearing is scheduled for the second quarter, 2003.

Casecnan Stockholder Litigation

Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro forma financial projections of the Casecnan Project prepared following commencement of commercial operations, in February 2002, MidAmerican, through its indirect wholly owned subsidiary CE Casecnan Ltd., advised the minority stockholder LaPrairie Group Contractors (International) Ltd., ("LPG"), that MidAmerican's indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against, inter alia, CE Casecnan Ltd. and MidAmerican. In the complaint, LPG seeks compensatory and punitive damages for alleged breaches of the stockholder agreement and alleged breaches of fiduciary duties allegedly owed by CE Casecnan Ltd. and MidAmerican to LPG. The complaint also seeks injunctive relief against all defendants and a declaratory judgment that LPG is entitled to maintain its 15% interest in CE Casecnan. The impact, if any, of this litigation on the Company cannot be determined at this time.

In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. ("San Lorenzo"), an original shareholder substantially all of whose shares in CE Casecnan a subsidiary of the Company purchased in 1998, threatened to initiate legal action in the Philippines in connection with certain aspects of its option to repurchase such shares on or prior to commercial operation of the Project. CE Casecnan believes that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, will vigorously defend any such action.

21.    Segment Information:

With its 2002 acquisitions of Kern River and Northern Natural Gas, the Company has identified seven reportable operating segments principally based on management structure: MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK, CalEnergy Generation-Domestic, CalEnergy Generation-Foreign, and HomeServices. Information related to the Company's reportable operating segments is shown below (in thousands).

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Year Ended December 31,		 March 14, 2000
through
December 31, 2000		 MEHC
(Predecessor)
January 1, 2000
through
March 13, 2000
  2002 2001
Operating revenue:
MidAmerican Energy $ 2,240,879   $ 2,388,650   $ 1,860,499   $ 455,844  
Kern River   127,254     —     —     —  
Northern Natural Gas   176,880     —     —     —  
CE Electric UK   795,366     1,443,997     1,499,768     498,142  
CalEnergy Generation – Domestic   38,546     37,299     2,757     438  
CalEnergy Generation – Foreign   326,316     203,482     146,798     40,124  
HomeServices   1,138,332     641,934     408,492     60,603  
    Segment operating revenue   4,843,573     4,715,362     3,918,314     1,055,151  
Corporate/other   (49,563 )    (18,581 )    (214 )    1,214  
Total operating revenue $ 4,794,010   $ 4,696,781   $ 3,918,100   $ 1,056,365  
Depreciation and amortization:
MidAmerican Energy $ 269,412   $ 286,590   $ 184,955   $ 45,184  
Kern River   17,165     —     —     —  
Northern Natural Gas   18,151     —     —     —  
CE Electric UK   116,792     133,865     108,637     31,964  
CalEnergy Generation – Domestic   8,714     5,439     2,183     250  
CalEnergy Generation – Foreign   88,036     66,315     52,685     13,514  
HomeServices   22,072     17,201     8,695     2,891  
    Segment depreciation and amortization   540,342     509,410     357,155     93,803  
Corporate/other   (14,440 )    29,292     26,196     3,475  
Total depreciation and amortization $ 525,902   $ 538,702   $ 383,351   $ 97,278  
Interest expense, net:
MidAmerican Energy $ 119,225   $ 113,980   $ 94,425   $ 24,579  
Kern River   33,036     —     —     —  
Northern Natural Gas   22,987     —     —     —  
CE Electric UK   183,472     112,308     74,335     21,189  
CalEnergy Generation – Domestic   20,913     10,835     1,829     793  
CalEnergy Generation – Foreign   68,338     30,875     34,458     9,713  
HomeServices   4,256     3,884     2,328     785  
    Segment interest expense, net   452,227     271,882     207,375     57,059  
Corporate/other   157,683     140,912     104,029     28,755  
Total interest expense, net $ 609,910   $ 412,794   $ 311,404   $ 85,814  

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Year Ended December 31,		 March 14, 2000
through
December 31, 2000		 MEHC
(Predecessor)
January 1, 2000
through
March 13, 2000
  2002 2001
Income before provisions for income taxes:
MidAmerican Energy $ 241,005   $ 211,300   $ 181,797   $ 63,315  
Kern River   60,700     —     —     —  
Northern Natural Gas   42,882     —     —     —  
CE Electric UK   266,755     173,816     83,108     58,673  
CalEnergy Generation – Domestic   (4,963 )    46,765     30,697     2,877  
CalEnergy Generation – Foreign   149,915     94,542     49,787     15,976  
HomeServices   69,979     42,945     31,015     (4,929 ) 
    Segment income before provision for     income taxes   826,273     569,368     376,404     135,912  
Corporate/other   (183,175 )    (65,484 )    (157,200 )    (44,742 ) 
Total income before provision for income taxes $ 643,098   $ 503,884   $ 219,204   $ 91,170  
Provision for income taxes:
MidAmerican Energy $ 99,782   $ 95,688   $ 77,450   $ 27,943  
Kern River   23,014     —     —     —  
Northern Natural Gas   16,947     —     —     —  
CE Electric UK   25,245     163,253     30,065     18,761  
CalEnergy Generation – Domestic   (15,203 )    2,706     (1,929 )    (8 ) 
CalEnergy Generation – Foreign   37,577     29,712     29,194     373  
HomeServices   28,207     15,953     12,300     (1,992 ) 
    Segment provision for income taxes   215,569     307,312     147,080     45,077  
Corporate/other   (115,981 )    (57,248 )    (93,803 )    (14,069 ) 
Total provision for income taxes $ 99,588   $ 250,064   $ 53,277   $ 31,008  
Capital expenditures:
MidAmerican Energy $ 358,194   $ 252,615   $ 194,045   $ 23,977  
Kern River   769,464     —     —     —  
Northern Natural Gas   62,409     —     —     —  
CE Electric UK   222,622     176,464     95,806     22,210  
CalEnergy Generation – Domestic   61,920     52,940     151,289     53,011  
CalEnergy Generation – Foreign   7,830     83,954     87,781     22,263  
HomeServices   18,273     9,878     6,996     2,052  
    Segment capital expenditures   1,500,712     575,851     535,917     123,513  
Corporate/other   7,373     901     2,812     28  
Total capital expenditures $ 1,508,085   $ 576,752   $ 538,729   $ 123,541  

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  As of December 31,
  2002 2001
Identifiable assets:
MidAmerican Energy $ 6,034,742   $ 5,848,035  
Kern River   1,797,850     —  
Northern Natural Gas   2,162,367     —  
CE Electric UK   4,717,524     4,340,147  
CalEnergy Generation – Domestic   909,832     870,664  
CalEnergy Generation – Foreign   974,852     950,035  
HomeServices   488,270     322,552  
    Segment identifiable assets   17,085,437     12,331,433  
Corporate/other   931,018     295,219  
Total identifiable assets $ 18,016,455   $ 12,626,652  
Long-lived assets:
MidAmerican Energy $ 4,999,637   $ 4,879,884  
Kern River   1,594,225     —  
Northern Natural Gas   1,818,469     —  
CE Electric UK   3,936,598     3,650,385  
CalEnergy Generation – Domestic   594,282     571,404  
CalEnergy Generation – Foreign   724,908     805,050  
HomeServices   384,899     262,175  
    Segment long-lived assets   14,053,018     10,168,898  
Corporate/other   15,201     7,019  
Total long-lived assets $ 14,068,219   $ 10,175,917  

The remaining differences from the segment amounts to the consolidated amounts described as "Corporate/Other" relate principally to the corporate functions including administrative costs, corporate cash and related interest income, intersegment eliminations, and fair value adjustments relating to acquisitions.

Excess of cost over fair value as of December 31, 2001 and changes for the period from January 1, 2002 through December 31, 2002 by segment is as follows:


  MidAmerican
Energy		 Kern River Northern
Natural Gas		 CE Electric
UK		 CalEnergy
Generation-
Domestic		 Home-
Services		 Total
Goodwill at December 31, 2001 $ 2,160,004   $ —   $ —   $ 1,104,262   $ 142,726   $ 231,554   $ 3,638,546  
Acquisitions/purchase price accounting adjustments   —     32,547     414,721     56,626     —     108,914     612,808  
Goodwill written off related tosale of business unit   —     —     —     (49,587 )    —     —     (49,587 ) 
Translation adjustment   —     —     —     86,296     —     —     86,296  
Other adjustments                                          
Deferred tax adjustments   (8,946 )    —     —     (1,675 )    (15,962 )    (477 )    (27,060 ) 
Stock option adjustments   (1,776 )    —     —     (601 )    (324 )    (170 )    (2,871 ) 
Goodwill at December 31, 2002 $ 2,149,282   $ 32,547   $ 414,721   $ 1,195,321   $ 126,440   $ 339,821   $ 4,258,132  

F-60

DEALER PROSPECTUS DELIVERY OBLIGATION

Until July 22, 2003, all dealers that effect transactions in these securities, whether or not participating in the offering, may be required to deliver a prospectus. This is in addition to the dealer's obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

All tendered original series C notes, executed letters of transmittal, and other related documents should be directed to the exchange agent. Requests for assistance and for additional copies of this prospectus, the letter of transmittal and other related documents should be directed to the exchange agent.

EXCHANGE AGENT:

THE BANK OF NEW YORK

By Facsimile:
(212) 298-1915

Confirm by telephone:
(212) 815-5920

By Mail, Hand or Courier:
The Bank of New York
Corporate Trust Department
Reorganization Unit
101 Barclay Street
Floor 7 East
New York, New York 10286

PART II
INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20.    Indemnification of Directors and Officers

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to the Registrant's directors and officers pursuant to the following provisions or otherwise, the Registrant has been advised that, although the validity and scope of the governing statute have not been tested in court, in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In addition, indemnification may be limited by state securities laws.

Sections 490.850-490.859 of the Iowa Business Corporation Act permit corporations organized thereunder to indemnify directors, officers, employees and agents against liability under certain circumstances. The Restated Articles of Incorporation, as amended, and the Restated Bylaws, as amended, of MidAmerican Energy Holdings Company provide for indemnification of directors, officers and employees to the full extent provided by the Iowa Business Corporation Act. The Articles of Incorporation and the Bylaws state that the indemnification provided therein shall not be deemed exclusive. MidAmerican Energy Holdings Company may purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of MidAmerican Energy Holdings Company or another corporation, partnership, joint venture, trust or other enterprise against any expense, liability or loss, whether or not MidAmerican Energy Holdings Company would have the power to indemnify such person against such expense, liability or loss under the Iowa Business Corporation Act. Pursuant to Section 490.857 of the Iowa Business Corporation Act, the Articles of Incorporation and the Bylaws, MidAmerican Energy Holdings Company, through MidAmerican Energy Holdings Company, maintains directors' and officers' liability insurance coverage. MidAmerican Energy Holdings Company has also entered into indemnification agreements with certain directors and officers, and expects to enter into similar agreements with future directors and officers, to further assure such persons indemnification as permitted by Iowa law.

As permitted by Section 490.202 of the Iowa Business Corporation Act and Article XI.B. of the Articles of Incorporation, the Articles of Incorporation are deemed to provide that no director shall be personally liable to MidAmerican Energy Holdings Company or its shareholders for money damages for any action taken, or any failure to take any action, as a director, except liability for any of the following: (1) the amount of a financial benefit received by a director to which the director is not entitled; (2) an intentional infliction of harm on the corporation or the shareholders; (3) a violation of section 490.833 (relating to certain unlawful distributions to shareholders); or (4) an intentional violation of criminal law.

The Registrant's Amended and Restated Articles of Incorporation and Bylaws provides that if the proceeding for which indemnification is sought is by or in the right of the Registrant, indemnification may be made only for reasonable expenses and may not be made in any proceeding in which the person is adjudged liable to the Registrant. Further, any such person may not be indemnified in any proceeding that charges improper personal benefit to the person in which the person is adjudged to be liable.

The Registrant's Amended and Restated Articles of Incorporation and Bylaws allow the Registrant to maintain liability insurance to protect itself and any director, officer, employee, or agent against any expense, liability or loss whether or not the Registrant would have the power to indemnify such person against such incurred expense, liability, or loss.

The Registrant has also entered into indemnification agreements with certain directors and officers, and expects to enter into similar agreements with future directors and officers, to further assure such persons' indemnification as permitted by Iowa law.

The rights to indemnification conferred on any person by the Registrant's Amended and Restated Articles of Incorporation and Bylaws are not exclusive of any right which any person may have or acquire under any statute, provision of the Registrant's Amended and Restated Articles of Incorporation, Bylaws, agreement, or vote of shareholders or disinterested directors.

II-1

Item 21.    Exhibits and Financial Statement Schedules.

(a) Exhibits


Exhibit No. Description
  3.1   Amended and Restated Articles of Incorporation of MEHC effective March 6, 2002. (incorporated by reference to Exhibit 3.3 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).
  3.2   Bylaws of MEHC (incorporated by reference to Exhibit 3.2 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  4.1   Indenture, dated as of October 4, 2002, by and between MEHC and The Bank of New York, relating to the 4.625% Senior Notes due 2007, the 5.875% Senior Notes due 2012 and the 3.50% Senior Notes due 2008 (incorporated by reference to Exhibit 4.1 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.2   First Supplemental Indenture, dated as of October 4, 2002, by and between MEHC and The Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit 4.2 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.3   Second Supplemental Indenture, dated as of May 16, 2003, by and between MEHC and the Bank of New York relating to the 3.50% Senior Notes due 2008.*
  4.4   Registration Rights Agreement, dated as of May 13, 2003, by and between MEHC and Credit Suisse First Boston LLC (as Representative for the Initial Purchasers).*
  4.5   Indenture for the 6¼% Convertible Junior Subordinated Debentures due 2012, dated as of February 26, 1997, between MEHC, as issuer, and the Bank of New York, as Trustee (incorporated by reference to Exhibit 10.129 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1995).
  4.6   Indenture, dated as of October 15, 1997, among MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to MEHC's Current Report on Form 8-K dated October 23, 1997).
  4.7   Form of First Supplemental Indenture for the 7.63% Senior Notes in the principal amount of $350,000,000 due 2007, dated as of October 28, 1997, among MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to MEHC's Current Report on Form 8-K dated October 23, 1997).
  4.8   Form of Second Supplemental Indenture for the 6.96% Senior Notes in the principal amount of $215,000,000 due 2003, 7.23% Senior Notes in the principal amount of $260,000,000 due 2005, 7.52% Senior Notes in the principal amount of $450,000,000 due 2008, and 8.48% Senior Notes in the principal amount of $475,000,000 due 2028, dated as of September 22, 1998 between MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to MEHC's Current Report on Form 8-K dated September 17, 1998).
  4.9   Form of Third Supplemental Indenture for the 7.52% Senior Notes in the principal amount of $100,000,000 due 2008, dated as of November 13, 1998, between MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to MEHC's Current Report on Form 8-K dated November 10, 1998).
  4.10   Indenture, dated as of March 14, 2000, among MEHC and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.9 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  4.11   Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 14, 2000 (incorporated by reference to Exhibit 4.10 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  4.12   Indenture, dated as of March 12, 2002 between MEHC and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.11 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).

II-2


Exhibit No. Description
  4.13   Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 7, 2002 (incorporated by reference to Exhibit 4.12 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).
  4.14   Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 12, 2002 (incorporated by reference to Exhibit 4.13 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).
  4.15   Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of August 16, 2002 (incorporated by reference to Exhibit 4.14 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.16   Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of March 12, 2002 (incorporated by reference to Exhibit 4.15 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.17   Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.16 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.18   Indenture, dated as of August 16, 2002 between MEHC and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.17 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.19   Subscription Agreement executed by Berkshire Hathaway Inc. dated as of August 16, 2002 (incorporated by reference to Exhibit 4.18 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.20   Shareholders Agreement dated as of March 14, 2000 (incorporated by reference to Exhibit 4.19 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  5.1   Opinion of Willkie Farr & Gallagher.**
  8.1   Opinion of Willkie Farr & Gallagher with respect to certain tax matters.**
  10.1   Employment Agreement between MEHC and David L. Sokol, dated May 10, 1999 (incorporated by reference to Exhibit 10.1 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  10.2   Amendment No. 1 to the Amended and Restated Employment Agreement between MEHC and David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.2 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  10.3   Non-Qualified Stock Options Agreements of David L. Sokol dated March 14, 2000 (incorporated by reference to Exhibit 10.3 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  10.4   Amended and Restated Employment Agreement between MEHC and Gregory E. Abel, dated May 10, 1999 (incorporated by reference to Exhibit 10.3 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  10.5   Non-Qualified Stock Options Agreements of Gregory E. Abel dated March 14, 2000 (incorporated by reference to Exhibit 10.5 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  10.6   Employment Agreement between MEHC and Patrick J. Goodman, dated April 21, 1999 (incorporated by reference to Exhibit 10.5 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  10.7   MidAmerican Energy Holdings Company Amended and Restated Long Term Incentive Partnership Plan dated January 1, 2003 (incorporated by reference to Exhibit 10.1 to MEHC's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003).

II-3


Exhibit No. Description
  10.8   125 MW Power Plant—Upper Mahiao Agreement dated September 6, 1993 between PNOC-Energy Development Corporation and Ormat, Inc. as amended by the First Amendment to 125 MW Power Plant Upper Mahiao Agreement dated as of January 28, 1994, the Letter Agreement dated February 10, 1994, the Letter Agreement dated February 18, 1994 and the Fourth Amendment to 125 MW Power Plant—Upper Mahiao Agreement dated as of March 7, 1994 (incorporated by reference to Exhibit 10.95 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.9   Credit Agreement dated April 8, 1994 among CE Cebu Geothermal Power Company, Inc., the Banks thereto, Credit Suisse as Agent (incorporated by reference to Exhibit 10.96 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.10   Credit Agreement dated as of April 8, 1994 between CE Cebu Geothermal Power Company, Inc., Export-Import Bank of the United States (incorporated by reference to Exhibit 10.97 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.11   Pledge Agreement among CE Philippines Ltd, Ormat-Cebu Ltd., Credit Suisse as Collateral Agent and CE Cebu Geothermal Power Company, Inc. dated as of April 8, 1994 (incorporated by reference to Exhibit 10.98 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.12   Overseas Private Investment Corporation Contract of Insurance dated April 8, 1994 between the Overseas Private Investment Corporation and MEHC through its subsidiaries CE International Ltd., CE Philippines Ltd., and Ormat-Cebu Ltd. (incorporated by reference to Exhibit 10.99 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.13   180 MW Power Plant—Mahanagdong Agreement dated September 18, 1993 between PNOC-Energy Development Corporation and CE Philippines Ltd. and MEHC, as amended by the First Amendment to Mahanagdong Agreement dated June 22, 1994, the Letter Agreement dated July 12, 1994, the Letter Agreement dated July 29, 1994, and the Fourth Amendment to Mahanagdong Agreement dated March 3, 1995 (incorporated by reference to Exhibit 10.100 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.14   Credit Agreement dated as of June 30, 1994 among CE Luzon Geothermal Power Company, Inc., American Pacific Finance Company, the Lenders party thereto, and Bank of America National Trust and Savings Association as Administrative Agent (incorporated by reference to Exhibit 10.101 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.15   Credit Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power Company, Inc. and Export-Import Bank of the United States (incorporated by reference to Exhibit 10.102 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.16   Finance Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power Company, Inc. and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.103 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.17   Pledge Agreement dated as of June 30, 1994 among CE Mahanagdong Ltd., Kiewit Energy International (Bermuda) Ltd., Bank of America National Trust and Savings Association as Collateral Agent and CE Luzon Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.104 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).

II-4


Exhibit No. Description
  10.18   Overseas Private Investment Corporation Contract of Insurance dated July 29, 1994 between Overseas Private Investment Corporation and MEHC, CE International Ltd., CE Mahanagdong Ltd. and American Pacific Finance Company and Amendment No. 1 dated August 3, 1994 (incorporated by reference to Exhibit 10.105 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.19   231 MW Power Plant—Malitbog Agreement dated September 10, 1993 between PNOC-Energy Development Corporation and Magma Power Company and the First and Second Amendments thereto dated December 8, 1993 and March 10, 1994, respectively (incorporated by reference to Exhibit 10.106 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.20   Credit Agreement dated as of November 10, 1994 among Visayas Power Capital Corporation, the Banks parties thereto and Credit Suisse Bank Agent (incorporated by reference to Exhibit 10.107 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.21   Finance Agreement dated as of November 10, 1994 between Visayas Geothermal Power Company and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.108 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.22   Pledge and Security Agreement dated as of November 10, 1994 among Broad Street Contract Services, Inc., Magma Power Company, Magma Netherlands B.V. and Credit Suisse as Bank Agent (incorporated by reference to Exhibit 10.109 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.23   Overseas Private Investment Corporation Contract of Insurance dated December 21, 1994 between Overseas Private Investment Corporation and Magma Netherlands, B.V. (incorporated by reference to Exhibit 10.110 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.24   Agreement as to Certain Common Representations, Warranties, Covenants and Other Terms, dated November 10, 1994 between Visayas Geothermal Power Company, Visayas Power Capital Corporation, Credit Suisse, as Bank Agent, Overseas Private Investment Corporation and the Banks named therein (incorporated by reference to Exhibit 10.111 to MEHC's 1994 Annual Report on Form 10-K for the year ended December 31, 1993).
  10.25   Trust Indenture dated as of November 27, 1995 between the CE Casecnan Water and Energy Company, Inc. and Chemical Trust Company of California (incorporated by reference to Exhibit 4.1 to CE Casecnan Water and Energy Company, Inc.'s Registration Statement on Form S-4 dated January 25, 1996).
  10.26   Amended and Restated Casecnan Project Agreement between the National Irrigation Administration and CE Casecnan Water and Energy Company Inc. dated June 26, 1995 (incorporated by reference to Exhibit 10.1 to CE Casecnan Water and Energy Company, Inc.'s Registration Statement on Form S-4 dated January 25, 1996).
  10.27   Term Loan and Revolving Facility Agreement, dated as of October 28, 1996, among CE Electric UK Holdings, CE Electric UK plc and Credit Suisse (incorporated by reference to Exhibit 10.130 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1995).
  10.28   Indenture and First Supplemental Indenture, dated March 11, 1999, between MidAmerican Funding LLC and IBJ Whitehall Bank & Trust Company and the First Supplement thereto relating to the $700 million Senior Notes and Bonds (incorporated by reference to MEHC's Annual Report on Form 10-K for the year ended December 31, 1998).

II-5


Exhibit No. Description
  10.29   General Mortgage Indenture and Deed of Trust dated as of January 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-1 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).
  10.30   First Supplemental Indenture dated as of January 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-2 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).
  10.31   Second Supplemental Indenture dated as of January 15, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-3 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).
  10.32   Third Supplemental Indenture dated as of May 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4.4 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654).
  10.33   Fourth Supplemental Indenture dated as of October 1, 1994, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.5 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
  10.34   Fifth Supplemental Indenture dated as of November 1, 1994, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.6 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
  10.35   Sixth Supplemental Indenture dated as of July 1, 1995, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.15 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 1995, Commission File No. 1-11505).
  10.36   Indenture of Mortgage and Deed of Trust, dated as of March 1, 1947 (incorporated by reference to Exhibit 7B filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 2-6922).
  10.37   Sixth Supplemental Indenture dated as of July 1, 1967 (incorporated by reference to Exhibit 2.08 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 2-28806).
  10.38   Twentieth Supplemental Indenture dated as of May 1, 1982 (incorporated by reference to Exhibit 4.B.23 to the Iowa-Illinois Gas and Electric Company Quarterly Report on Form 10-Q for the period ended June 30, 1982, Commission File No. 1-3573).
  10.39   Resignation and Appointment of successor Individual Trustee (incorporated by reference to Exhibit 4.B.30 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 33-39211).
  10.40   Twenty-Eighth Supplemental Indenture dated as of May 15, 1992 (incorporated by reference to Exhibit 4.31.B to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated May 21, 1992, Commission File No. 1-3573).
  10.41   Twenty-Ninth Supplemental Indenture dated as of March 15, 1993 (incorporated by reference to Exhibit 4.32.A to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated March 24, 1993, Commission File No. 1-3573).
  10.42   Thirtieth Supplemental Indenture dated as of October 1, 1993 (incorporated by reference to Exhibit 4.34.A to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated October 7, 1993, Commission File No. 1-3573).

II-6


Exhibit No. Description
  10.43   Thirty-First Supplemental Indenture dated as of July 1, 1995, between Iowa-Illinois Gas and Electric Company and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.16 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended dated December 31, 1995, Commission File No. 1-11505).
  10.44   Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 4-C-2 filed by Iowa Power Inc. as part of Registration Statement No. 2-27681).
  10.45   Amendments Nos. 1 and 2 to Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District (incorporated by reference to Exhibit 4-C-2a filed by Iowa Power Inc. as part of Registration Statement No. 2-35624).
  10.46   Amendment No. 3 dated August 31, 1970, to the Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 5-C-2-b filed by Iowa Power Inc. as part of Registration Statement No. 2-42191).
  10.47   Amendment No. 4 dated March 28, 1974, to the Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 5-C-2-c filed by Iowa Power Inc. as part of Registration Statement No. 2-51540).
  10.48   Amendment No. 5 dated September 2, 1997, to the Power Sales Contract between MidAmerican Energy Company and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 10.2 to the former MidAmerican Energy Holdings Company and MidAmerican Energy Company respective Quarterly Reports on the combined Form 10-Q for the quarter ended September 30, 1997, Commission File Nos. 333-90553 and 1-11505, respectively).
  10.49   Amendment No. 6 dated July 31, 2002, to the Power Sales Contract between MidAmerican Energy Company and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 10.1 to the MidAmerican Funding, LLC and MidAmerican Energy Company respective Quarterly Reports on the combined Form 10-Q for the quarter ended June 20, 2002, Commission File Nos. 1-12459 and 1-11505, respectively).
  10.50   CalEnergy Company, Inc. Voluntary Deferred Compensation Plan effective December 1, 1997, First Amendment dated as of August 17, 1999 and Second Amendment effective March 2000 (incorporated by reference to Exhibit 10.50 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  10.51   MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan (incorporated by reference to Exhibit 10.51 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  10.52   MidAmerican Energy Company First Amended and Restated Supplemental Retirement Plan for Designated Officers dated as of May 10, 1999 (incorporated by reference to Exhibit 10.52 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  10.53   MidAmerican Energy Company Restated Executive Deferred Compensation Plan (incorporated by reference to Exhibit 10.6 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  10.54   MidAmerican Energy Holdings Company Restated Deferred Compensation Plan—Board of Directors (incorporated by reference to Exhibit 10 to MEHC's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).
  10.55   MidAmerican Energy Company Combined Midwest Resources/Iowa Resources Restated Deferred Compensation Plan—Board of Directors (incorporated by reference to Exhibit 10.63 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).

II-7


Exhibit No. Description
  10.56   Midwest Resources Inc. Supplemental Retirement Plan (formerly the Midwest Energy Company Supplemental Retirement Plan) (incorporated by reference to Exhibit 10.10 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654).
  10.57   Amendment No. 1 to the Midwest Resources Inc. Supplemental Retirement Plan (incorporated by reference to Exhibit 10.24 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
  10.58   Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan for Designated Officers, as amended as of July 28, 1994 (incorporated by reference to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-3573).
  10.59   Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Designated Officers, as amended as of July 1, 1993 (incorporated by reference to Exhibit 10.K.2 to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-3573).
  10.60   Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Key Employees, dated as of April 26, 1991 (incorporated by reference to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1991, Commission File No. 1-3573).
  10.61   Iowa-Illinois Gas and Electric Company Board of Directors' Compensation Deferral Plan (incorporated by reference to Exhibit 10.K.4 to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-3573).
  10.62   Iowa Utilities Board Settlement Agreement among MidAmerican Energy Company, Office of Consumer Advocate, Iowa Energy Consumers, Aluminum Company of America, Deere & Company, Cargill Inc., U.S. Gypsum Company, Interstate Power Company and IES Utilities, Inc. (incorporated by reference to Exhibit 10.16 to the MidAmerican Funding, LLC and MidAmerican Energy Company respective Annual Reports on the combined Form 10-K for the year ended December 31, 2000, Commission File Nos. 333-90553 and 1-11505, respectively).
  10.63   Share Sale Agreement among NPower Yorkshire Limited, Innogy Holdings plc, CE Electric UK plc and Northern Electric plc dated as of August 6, 2001 (incorporated by reference to Exhibit 10.63 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  10.64   Purchase Agreement among The Williams Companies, Inc., Williams Gas Pipeline Company, LLC, Williams Western Pipeline Company LLC, Kern River Acquisition, LLC and MEHC, KR Holding, LLC, KR Acquisition 1, LLC and KR Acquisition 2, LLC, dated as of March 7, 2002 (incorporated by reference to Exhibit 99.2 to MEHC's Current Report on Form 8-K dated March 28, 2002).
  10.65   Stock Purchase Agreement among The Williams Companies, Inc., MEHC Investment, Inc. and MEHC dated as of March 7, 2002 (incorporated by reference to Exhibit 99.3 to MEHC's Current Report on Form 8-K dated March 28, 2002).
  10.66   Completion Guarantee given by MEHC to Union Bank of California, Administrative Agent, dated as of June 21, 2002 (incorporated by reference to Exhibit 99.2 to MEHC's Current Report on Form 8-K dated June 27, 2002).
  10.67   Purchase and Sale Agreement between Dynegy Inc., NNGC Holding Company, Inc. and MEHC, dated as of July 28, 2002 (incorporated by reference to Exhibit 99.2 to MEHC's Current Report on Form 8-K dated July 30, 2002).
  10.68   Executive Incremental Profit Sharing Plan (incorporated by reference to Exhibit 10.2 to MEHC's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003).
  12.1   Statement regarding Computation of Ratio of Earnings to Fixed Charges.*

II-8


Exhibit No. Description
  15.1   Awareness Letter of Independent Accountants.**
  21.1   Subsidiaries of the Registrant.*
  23.1   Consent of Willkie Farr & Gallagher (included in their opinions filed as Exhibits 5.1 and Exhibit 8.1).**
  23.2   Consent of Deloitte & Touche LLP.**
  24.1   Powers of Attorney.*
  25.1   Statement on Form T-1 of Eligibility of Trustee relating to the 3.50% Senior Notes due 2008.*
  99.1   Form of Letter of Transmittal relating to the 3.50% Senior Notes due 2008.*
  99.2   Form of Notice of Guaranteed Delivery relating to the 3.50% Senior Notes due 2008.*
  99.3   Form of Letter to Clients relating to the 3.50% Senior Notes due 2008.*
  99.4   Form of Letter to Nominees relating to the 3.50% Senior Notes due 2008.*
*    Previously filed.
**   Filed herewith.

II-9

Item 22.    Undertakings

The undersigned registrant hereby undertakes that, for the purposes of determining any liability under the Securities Act, each filing of the registrant's annual report pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan's annual report pursuant to Section 15(d) of the Exchange Act) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant, pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by any such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether or not such indemnification is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective
(2) For purposes of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned registrant hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Item 4, 10(b), 11 or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

The undersigned registrant hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

II-10

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Des Moines, State of Iowa, on the 11th day of June, 2003.

MIDAMERICAN ENERGY HOLDINGS COMPANY

By: /s/    Douglas L. Anderson

Douglas L. Anderson
Senior Vice President and General Counsel

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons, in the capacities and on the dates indicated.

Signature Title Date
* Chairman of the Board of Directors, Chief Executive Officer and Director (principal executive officer) June 11, 2003
David L. Sokol
* President, Chief Operating Officer and Director June 11, 2003
Gregory E. Abel
* Senior Vice President and Chief
Financial Officer (principal financial officer)		 June 11, 2003
Patrick J. Goodman
* Director June 11, 2003
Edgar D. Aronson
* Director June 11, 2003
Stanley J. Bright
* Director June 11, 2003
Walter Scott, Jr.
* Director June 11, 2003
Marc D. Hamburg
* Director June 11, 2003
Warren E. Buffett
* Director June 11, 2003
John K. Boyer
* Director June 11, 2003
W. David Scott
* Director June 11, 2003
Richard R. Jaros

Douglas L. Anderson, by signing his name below, signs this document on behalf of each of the above-named persons specified by an asterisk (*) pursuant to a power of attorney duly executed by such persons filed with the Securities and Exchange Commission in the Registrant's Registration Statement on Form S-4 on May 30, 2003.

            /s/ Douglas L. Anderson        
               Douglas L. Anderson
                    Attorney-in-fact

II-11


MidAmerican Energy Holdings Company
Parent Company Only
Condensed Balance Sheets		 SCHEDULE I

As of December 31, 2002 and 2001
(In thousands)


  2002 2001
ASSETS            
Current assets –            
Cash and cash equivalents $ 320,629   $ 2,524  
Investments in and advances to subsidiaries and joint ventures   5,459,832     3,432,528  
Equipment, net   15,984     17,605  
Excess of cost over fair value of net assets acquired   1,185,963     1,211,814  
Deferred charges and other assets   151,126     129,501  
Total assets $ 7,133,534   $ 4,793,972  
             
LIABILITIES AND STOCKHOLDERS' EQUITY            
Current liabilities:            
Accounts payable and other accrued liabilities $ 94,389   $ 68,445  
Current portion of long-term debt   215,000     —  
Short-term debt   —     153,500  
Total current liabilities   309,389     221,945  
Non-current liabilities   11,885     6,480  
Notes payable – affiliate   94,795     197,153  
Parent company debt   2,324,457     1,834,498  
Total liabilities   2,740,526     2,260,076  
Deferred income   35,313     37,578  
Company-obligated mandatorily redeemable preferred securities
of subsidiary trusts 		  2,063,412     788,151  
Stockholders' equity:            
Zero coupon convertible preferred stock – authorized 50,000 shares, no par value, 41,263 and 34,563 shares issued and outstanding at December 31, 2002 and 2001   —     —  
Common stock – authorized 60,000 shares, no par value; 9,281 shares issued and outstanding at December 31, 2002 and 2001   —     —  
Additional paid in capital   1,956,509     1,553,073  
Retained earnings   584,009     223,926  
Accumulated other comprehensive loss, net   (246,235 )    (68,832 ) 
Total stockholders' equity   2,294,283     1,708,167  
Total liabilities and stockholders' equity $ 7,133,534   $ 4,793,972  

The notes to the consolidated MEHC financial statements are an integral part of this
financial statement schedule.

S-1


MidAmerican Energy Holdings Company
Parent Company Only
Condensed Statements of Operations		 SCHEDULE I

For the three years ended December 31, 2002
(In thousands)


  2002 2001 2000
Revenue:            
Equity in undistributed earnings of subsidiary companies
and joint ventures		 $ 460,631   $ 608,896   $ 390,194  
Cash dividends and distributions from subsidiary companies
and joint ventures		   351,847     87,625     96,342  
Interest and other income   18,243     2,248     13,818  
Total revenue   830,721     698,769     500,354  
             
Costs and expenses:            
General and administration   29,368     41,078     45,089  
Depreciation and amortization   815     31,537     25,716  
Interest, net of capitalized interest   173,240     148,680     141,891  
Total costs and expenses   203,423     221,295     212,696  
Income before provision for income taxes   627,298     477,474     287,658  
Provision for income taxes   99,588     250,064     84,285  
Income before minority interest   527,710     227,410     203,373  
Minority interest   147,667     80,137     70,804  
Income before and cumulative effect of change in accounting principle   380,043     147,273     132,569  
Cumulative effect of change in accounting principle, net of tax   —     (4,604 )    —  
Net income available to common stockholders $ 380,043   $ 142,669   $ 132,569  

The notes to the consolidated MEHC financial statements are an integral part of this
financial statement schedule.

S-2


MidAmerican Energy Holdings Company
Parent Company Only
Condensed Statements of Cash Flows		 SCHEDULE I

For the three years ended December 31, 2002
(In thousands)


  2002 2001 2000
Cash flows from operating activities $ (188,300 )  $ (272,906 )  $ (299,862 ) 
             
Cash flows from investing activities:            
Decrease (increase) in advances to and investments in subsidiaries and joint ventures   (1,692,742 )    204,118     143,052  
Acquisition of MEHC (Predecessor)   —     —     (2,048,266 ) 
Other, net   10,307     (5,297 )    28,458  
Net cash flows from investing activities   (1,682,435 )    198,821     (1,876,756 ) 
Cash flows from financing activities:            
Proceeds from issuance of common and preferred stock   402,000     —     1,428,024  
Proceeds from issuance of trust preferred securities   1,273,000     —     454,772  
Proceeds from issuances of parent company debt   700,000     —     —  
Repayments of parent company debt   —     (32 )    —  
Net (repayment of) proceeds from revolver   (153,500 )    68,500     85,000  
Other   (32,660 )    (82 )    (23,893 ) 
Net cash flows from financing activities   2,188,840     68,386     1,943,903  
Net increase (decrease) in cash and cash equivalents   318,105     (5,699 )    (232,715 ) 
Cash and cash equivalents at beginning of year   2,524     8,223     240,938  
Cash and cash equivalents at end of year $ 320,629   $ 2,524   $ 8,223  
Supplemental disclosures:            
Interest paid, net of interest capitalized $ 164,267   $ 148,999   $ 144,147  
Income taxes paid $ 101,225   $ 133,139   $ 94,405  

The notes to the consolidated MEHC financial statements are an integral part of this
financial statement schedule.

S-3

SCHEDULE II

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2002
(In thousands)


Column A Column B Column C Column D Column E
  Balance at
Beginning
of Year		 Additions Deductions Balance at
End
of Year
Description Charged
to Income		 Other
Accounts		 Acquisition
Reserves(2)
Reserves Deducted From Assets
To Which They Apply:
Reserve for uncollectible accounts
receivable:
Year ended 2002 $ 7,319   $ 27,782   $ —   $ 10,142   $ (5,501 )  $ 39,742  
Year ended 2001 $ 32,685   $ 17,061   $ —   $ —   $ (42,427 )  $ 7,319  
Year ended 2000 $ 18,666   $ 40,024   $ —   $ —   $ (26,005 )  $ 32,685  
Reserves Not Deducted From Assets (1):
Year ended 2002 $ 13,631   $ 2,798   $ 247   $ —   $ (5,695 )  $ 10,981  
Year ended 2001 $ 25,063   $ 5,046   $ —   $ —   $ (16,478 )  $ 13,631  
Year ended 2000 $ 17,696   $ 10,832   $ —   $ —   $ (3,465 )  $ 25,063  
(1) Reserves not deducted from assets include estimated liabilities for losses retained by MEHC for workers compensation, public liability and property damage claims.
(2) Acquisition reserves represent the reserve recorded at Kern River and Northern Natural Gas at the date of acquisition.

The notes to the consolidated MEHC financial statements are an integral part of this financial
statement schedule.

S-4

EXHIBIT INDEX


Exhibit No. Description
  3.1   Amended and Restated Articles of Incorporation of MEHC effective March 6, 2002. (incorporated by reference to Exhibit 3.3 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).
  3.2   Bylaws of MEHC (incorporated by reference to Exhibit 3.2 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  4.1   Indenture, dated as of October 4, 2002, by and between MEHC and The Bank of New York, relating to the 4.625% Senior Notes due 2007, the 5.875% Senior Notes due 2012 and the 3.50% Senior Notes due 2008 (incorporated by reference to Exhibit 4.1 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.2   First Supplemental Indenture, dated as of October 4, 2002, by and between MEHC and The Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit 4.2 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.3   Second Supplemental Indenture, dated as of May 16, 2003, by and between MEHC and the Bank of New York relating to the 3.50% Senior Notes due 2008.*
  4.4   Registration Rights Agreement, dated as of May 13, 2003, by and between MEHC and Credit Suisse First Boston LLC (as Representative for the Initial Purchasers).*
  4.5   Indenture for the 6¼% Convertible Junior Subordinated Debentures due 2012, dated as of February 26, 1997, between MEHC, as issuer, and the Bank of New York, as Trustee (incorporated by reference to Exhibit 10.129 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1995).
  4.6   Indenture, dated as of October 15, 1997, among MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to MEHC's Current Report on Form 8-K dated October 23, 1997).
  4.7   Form of First Supplemental Indenture for the 7.63% Senior Notes in the principal amount of $350,000,000 due 2007, dated as of October 28, 1997, among MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to MEHC's Current Report on Form 8-K dated October 23, 1997).
  4.8   Form of Second Supplemental Indenture for the 6.96% Senior Notes in the principal amount of $215,000,000 due 2003, 7.23% Senior Notes in the principal amount of $260,000,000 due 2005, 7.52% Senior Notes in the principal amount of $450,000,000 due 2008, and 8.48% Senior Notes in the principal amount of $475,000,000 due 2028, dated as of September 22, 1998 between MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to MEHC's Current Report on Form 8-K dated September 17, 1998).
  4.9   Form of Third Supplemental Indenture for the 7.52% Senior Notes in the principal amount of $100,000,000 due 2008, dated as of November 13, 1998, between MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to MEHC's Current Report on Form 8-K dated November 10, 1998).
  4.10   Indenture, dated as of March 14, 2000, among MEHC and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.9 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  4.11   Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 14, 2000 (incorporated by reference to Exhibit 4.10 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).

Exhibit No. Description
  4.12   Indenture, dated as of March 12, 2002 between MEHC and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.11 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).
  4.13   Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 7, 2002 (incorporated by reference to Exhibit 4.12 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).
  4.14   Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 12, 2002 (incorporated by reference to Exhibit 4.13 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).
  4.15   Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of August 16, 2002 (incorporated by reference to Exhibit 4.14 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.16   Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of March 12, 2002 (incorporated by reference to Exhibit 4.15 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.17   Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.16 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.18   Indenture, dated as of August 16, 2002 between MEHC and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.17 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.19   Subscription Agreement executed by Berkshire Hathaway Inc. dated as of August 16, 2002 (incorporated by reference to Exhibit 4.18 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  4.20   Shareholders Agreement dated as of March 14, 2000 (incorporated by reference to Exhibit 4.19 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  5.1   Opinion of Willkie Farr & Gallagher.**
  8.1   Opinion of Willkie Farr & Gallagher with respect to certain tax matters.**
  10.1   Employment Agreement between MEHC and David L. Sokol, dated May 10, 1999 (incorporated by reference to Exhibit 10.1 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  10.2   Amendment No. 1 to the Amended and Restated Employment Agreement between MEHC and David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.2 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  10.3   Non-Qualified Stock Options Agreements of David L. Sokol dated March 14, 2000 (incorporated by reference to Exhibit 10.3 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  10.4   Amended and Restated Employment Agreement between MEHC and Gregory E. Abel, dated May 10, 1999 (incorporated by reference to Exhibit 10.3 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  10.5   Non-Qualified Stock Options Agreements of Gregory E. Abel dated March 14, 2000 (incorporated by reference to Exhibit 10.5 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).

Exhibit No. Description
  10.6   Employment Agreement between MEHC and Patrick J. Goodman, dated April 21, 1999 (incorporated by reference to Exhibit 10.5 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  10.7   MidAmerican Energy Holdings Company Amended and Restated Long Term Incentive Partnership Plan dated January 1, 2003 (incorporated by reference to Exhibit 10.1 to MEHC's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003).
  10.8   125 MW Power Plant—Upper Mahiao Agreement dated September 6, 1993 between PNOC-Energy Development Corporation and Ormat, Inc. as amended by the First Amendment to 125 MW Power Plant Upper Mahiao Agreement dated as of January 28, 1994, the Letter Agreement dated February 10, 1994, the Letter Agreement dated February 18, 1994 and the Fourth Amendment to 125 MW Power Plant—Upper Mahiao Agreement dated as of March 7, 1994 (incorporated by reference to Exhibit 10.95 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.9   Credit Agreement dated April 8, 1994 among CE Cebu Geothermal Power Company, Inc., the Banks thereto, Credit Suisse as Agent (incorporated by reference to Exhibit 10.96 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.10   Credit Agreement dated as of April 8, 1994 between CE Cebu Geothermal Power Company, Inc., Export-Import Bank of the United States (incorporated by reference to Exhibit 10.97 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.11   Pledge Agreement among CE Philippines Ltd, Ormat-Cebu Ltd., Credit Suisse as Collateral Agent and CE Cebu Geothermal Power Company, Inc. dated as of April 8, 1994 (incorporated by reference to Exhibit 10.98 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.12   Overseas Private Investment Corporation Contract of Insurance dated April 8, 1994 between the Overseas Private Investment Corporation and MEHC through its subsidiaries CE International Ltd., CE Philippines Ltd., and Ormat-Cebu Ltd. (incorporated by reference to Exhibit 10.99 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.13   180 MW Power Plant—Mahanagdong Agreement dated September 18, 1993 between PNOC-Energy Development Corporation and CE Philippines Ltd. and MEHC, as amended by the First Amendment to Mahanagdong Agreement dated June 22, 1994, the Letter Agreement dated July 12, 1994, the Letter Agreement dated July 29, 1994, and the Fourth Amendment to Mahanagdong Agreement dated March 3, 1995 (incorporated by reference to Exhibit 10.100 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.14   Credit Agreement dated as of June 30, 1994 among CE Luzon Geothermal Power Company, Inc., American Pacific Finance Company, the Lenders party thereto, and Bank of America National Trust and Savings Association as Administrative Agent (incorporated by reference to Exhibit 10.101 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.15   Credit Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power Company, Inc. and Export-Import Bank of the United States (incorporated by reference to Exhibit 10.102 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).

Exhibit No. Description
  10.16   Finance Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power Company, Inc. and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.103 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.17   Pledge Agreement dated as of June 30, 1994 among CE Mahanagdong Ltd., Kiewit Energy International (Bermuda) Ltd., Bank of America National Trust and Savings Association as Collateral Agent and CE Luzon Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.104 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.18   Overseas Private Investment Corporation Contract of Insurance dated July 29, 1994 between Overseas Private Investment Corporation and MEHC, CE International Ltd., CE Mahanagdong Ltd. and American Pacific Finance Company and Amendment No. 1 dated August 3, 1994 (incorporated by reference to Exhibit 10.105 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.19   231 MW Power Plant—Malitbog Agreement dated September 10, 1993 between PNOC-Energy Development Corporation and Magma Power Company and the First and Second Amendments thereto dated December 8, 1993 and March 10, 1994, respectively (incorporated by reference to Exhibit 10.106 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.20   Credit Agreement dated as of November 10, 1994 among Visayas Power Capital Corporation, the Banks parties thereto and Credit Suisse Bank Agent (incorporated by reference to Exhibit 10.107 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.21   Finance Agreement dated as of November 10, 1994 between Visayas Geothermal Power Company and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.108 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.22   Pledge and Security Agreement dated as of November 10, 1994 among Broad Street Contract Services, Inc., Magma Power Company, Magma Netherlands B.V. and Credit Suisse as Bank Agent (incorporated by reference to Exhibit 10.109 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.23   Overseas Private Investment Corporation Contract of Insurance dated December 21, 1994 between Overseas Private Investment Corporation and Magma Netherlands, B.V. (incorporated by reference to Exhibit 10.110 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
  10.24   Agreement as to Certain Common Representations, Warranties, Covenants and Other Terms, dated November 10, 1994 between Visayas Geothermal Power Company, Visayas Power Capital Corporation, Credit Suisse, as Bank Agent, Overseas Private Investment Corporation and the Banks named therein (incorporated by reference to Exhibit 10.111 to MEHC's 1994 Annual Report on Form 10-K for the year ended December 31, 1993).
  10.25   Trust Indenture dated as of November 27, 1995 between the CE Casecnan Water and Energy Company, Inc. and Chemical Trust Company of California (incorporated by reference to Exhibit 4.1 to CE Casecnan Water and Energy Company, Inc.'s Registration Statement on Form S-4 dated January 25, 1996).
  10.26   Amended and Restated Casecnan Project Agreement between the National Irrigation Administration and CE Casecnan Water and Energy Company Inc. dated June 26, 1995 (incorporated by reference to Exhibit 10.1 to CE Casecnan Water and Energy Company, Inc.'s Registration Statement on Form S-4 dated January 25, 1996).

Exhibit No. Description
  10.27   Term Loan and Revolving Facility Agreement, dated as of October 28, 1996, among CE Electric UK Holdings, CE Electric UK plc and Credit Suisse (incorporated by reference to Exhibit 10.130 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1995).
  10.28   Indenture and First Supplemental Indenture, dated March 11, 1999, between MidAmerican Funding LLC and IBJ Whitehall Bank & Trust Company and the First Supplement thereto relating to the $700 million Senior Notes and Bonds (incorporated by reference to MEHC's Annual Report on Form 10-K for the year ended December 31, 1998).
  10.29   General Mortgage Indenture and Deed of Trust dated as of January 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-1 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).
  10.30   First Supplemental Indenture dated as of January 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-2 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).
  10.31   Second Supplemental Indenture dated as of January 15, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-3 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).
  10.32   Third Supplemental Indenture dated as of May 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4.4 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654).
  10.33   Fourth Supplemental Indenture dated as of October 1, 1994, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.5 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
  10.34   Fifth Supplemental Indenture dated as of November 1, 1994, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.6 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
  10.35   Sixth Supplemental Indenture dated as of July 1, 1995, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.15 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 1995, Commission File No. 1-11505).
  10.36   Indenture of Mortgage and Deed of Trust, dated as of March 1, 1947 (incorporated by reference to Exhibit 7B filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 2-6922).
  10.37   Sixth Supplemental Indenture dated as of July 1, 1967 (incorporated by reference to Exhibit 2.08 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 2-28806).
  10.38   Twentieth Supplemental Indenture dated as of May 1, 1982 (incorporated by reference to Exhibit 4.B.23 to the Iowa-Illinois Gas and Electric Company Quarterly Report on Form 10-Q for the period ended June 30, 1982, Commission File No. 1-3573).

Exhibit No. Description
  10.39   Resignation and Appointment of successor Individual Trustee (incorporated by reference to Exhibit 4.B.30 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 33-39211).
  10.40   Twenty-Eighth Supplemental Indenture dated as of May 15, 1992 (incorporated by reference to Exhibit 4.31.B to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated May 21, 1992, Commission File No. 1-3573).
  10.41   Twenty-Ninth Supplemental Indenture dated as of March 15, 1993 (incorporated by reference to Exhibit 4.32.A to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated March 24, 1993, Commission File No. 1-3573).
  10.42   Thirtieth Supplemental Indenture dated as of October 1, 1993 (incorporated by reference to Exhibit 4.34.A to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated October 7, 1993, Commission File No. 1-3573).
  10.43   Thirty-First Supplemental Indenture dated as of July 1, 1995, between Iowa-Illinois Gas and Electric Company and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.16 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended dated December 31, 1995, Commission File No. 1-11505).
  10.44   Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 4-C-2 filed by Iowa Power Inc. as part of Registration Statement No. 2-27681).
  10.45   Amendments Nos. 1 and 2 to Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District (incorporated by reference to Exhibit 4-C-2a filed by Iowa Power Inc. as part of Registration Statement No. 2-35624).
  10.46   Amendment No. 3 dated August 31, 1970, to the Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 5-C-2-b filed by Iowa Power Inc. as part of Registration Statement No. 2-42191).
  10.47   Amendment No. 4 dated March 28, 1974, to the Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 5-C-2-c filed by Iowa Power Inc. as part of Registration Statement No. 2-51540).
  10.48   Amendment No. 5 dated September 2, 1997, to the Power Sales Contract between MidAmerican Energy Company and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 10.2 to the former MidAmerican Energy Holdings Company and MidAmerican Energy Company respective Quarterly Reports on the combined Form 10-Q for the quarter ended September 30, 1997, Commission File Nos. 333-90553 and 1-11505, respectively).
  10.49   Amendment No. 6 dated July 31, 2002, to the Power Sales Contract between MidAmerican Energy Company and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 10.1 to the MidAmerican Funding, LLC and MidAmerican Energy Company respective Quarterly Reports on the combined Form 10-Q for the quarter ended June 20, 2002, Commission File Nos. 1-12459 and 1-11505, respectively).
  10.50   CalEnergy Company, Inc. Voluntary Deferred Compensation Plan effective December 1, 1997, First Amendment dated as of August 17, 1999 and Second Amendment effective March 2000 (incorporated by reference to Exhibit 10.50 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).

Exhibit No. Description
  10.51   MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan (incorporated by reference to Exhibit 10.51 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  10.52   MidAmerican Energy Company First Amended and Restated Supplemental Retirement Plan for Designated Officers dated as of May 10, 1999 (incorporated by reference to Exhibit 10.52 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  10.53   MidAmerican Energy Company Restated Executive Deferred Compensation Plan (incorporated by reference to Exhibit 10.6 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  10.54   MidAmerican Energy Holdings Company Restated Deferred Compensation Plan—Board of Directors (incorporated by reference to Exhibit 10 to MEHC's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).
  10.55   MidAmerican Energy Company Combined Midwest Resources/Iowa Resources Restated Deferred Compensation Plan—Board of Directors (incorporated by reference to Exhibit 10.63 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
  10.56   Midwest Resources Inc. Supplemental Retirement Plan (formerly the Midwest Energy Company Supplemental Retirement Plan) (incorporated by reference to Exhibit 10.10 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654).
  10.57   Amendment No. 1 to the Midwest Resources Inc. Supplemental Retirement Plan (incorporated by reference to Exhibit 10.24 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
  10.58   Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan for Designated Officers, as amended as of July 28, 1994 (incorporated by reference to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-3573).
  10.59   Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Designated Officers, as amended as of July 1, 1993 (incorporated by reference to Exhibit 10.K.2 to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-3573).
  10.60   Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Key Employees, dated as of April 26, 1991 (incorporated by reference to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1991, Commission File No. 1-3573).
  10.61   Iowa-Illinois Gas and Electric Company Board of Directors' Compensation Deferral Plan (incorporated by reference to Exhibit 10.K.4 to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-3573).
  10.62   Iowa Utilities Board Settlement Agreement among MidAmerican Energy Company, Office of Consumer Advocate, Iowa Energy Consumers, Aluminum Company of America, Deere & Company, Cargill Inc., U.S. Gypsum Company, Interstate Power Company and IES Utilities, Inc. (incorporated by reference to Exhibit 10.16 to the MidAmerican Funding, LLC and MidAmerican Energy Company respective Annual Reports on the combined Form 10-K for the year ended December 31, 2000, Commission File Nos. 333-90553 and 1-11505, respectively).

Exhibit No. Description
  10.63   Share Sale Agreement among NPower Yorkshire Limited, Innogy Holdings plc, CE Electric UK plc and Northern Electric plc dated as of August 6, 2001 (incorporated by reference to Exhibit 10.63 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
  10.64   Purchase Agreement among The Williams Companies, Inc., Williams Gas Pipeline Company, LLC, Williams Western Pipeline Company LLC, Kern River Acquisition, LLC and MEHC, KR Holding, LLC, KR Acquisition 1, LLC and KR Acquisition 2, LLC, dated as of March 7, 2002 (incorporated by reference to Exhibit 99.2 to MEHC's Current Report on Form 8-K dated March 28, 2002).
  10.65   Stock Purchase Agreement among The Williams Companies, Inc., MEHC Investment, Inc. and MEHC dated as of March 7, 2002 (incorporated by reference to Exhibit 99.3 to MEHC's Current Report on Form 8-K dated March 28, 2002).
  10.66   Completion Guarantee given by MEHC to Union Bank of California, Administrative Agent, dated as of June 21, 2002 (incorporated by reference to Exhibit 99.2 to MEHC's Current Report on Form 8-K dated June 27, 2002).
  10.67   Purchase and Sale Agreement between Dynegy Inc., NNGC Holding Company, Inc. and MEHC, dated as of July 28, 2002 (incorporated by reference to Exhibit 99.2 to MEHC's Current Report on Form 8-K dated July 30, 2002).
  10.68   Executive Incremental Profit Sharing Plan (incorporated by reference to Exhibit 10.2 to MEHC's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003).
  12.1   Statement regarding Computation of Ratio of Earnings to Fixed Charges.*
  15.1   Awareness Letter of Independent Accountants.**
  21.1   Subsidiaries of the Registrant.*
  23.1   Consent of Willkie Farr & Gallagher (included in their opinions filed as Exhibits 5.1 and Exhibit 8.1).**
  23.2   Consent of Deloitte & Touche LLP.**
  24.1   Powers of Attorney.*
  25.1   Statement on Form T-1 of Eligibility of Trustee relating to the 3.50% Senior Notes due 2008.*
  99.1   Form of Letter of Transmittal relating to the 3.50% Senior Notes due 2008.*
  99.2   Form of Notice of Guaranteed Delivery relating to the 3.50% Senior Notes due 2008.*
  99.3   Form of Letter to Clients relating to the 3.50% Senior Notes due 2008.*
  99.4   Form of Letter to Nominees relating to the 3.50% Senior Notes due 2008.*
*    Previously filed.
**   Filed herewith